UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31,June 30, 2006
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Transition period from to
Commission File No. 1-15973
NORTHWEST NATURAL GAS COMPANY
(Exact name of registrant as specified in its charter)
Oregon | 93-0256722 | |
(State or other jurisdiction of
| (I.R.S. Employer
|
220 N.W. Second Avenue, Portland, Oregon 97209
(Address of principal executive offices) (Zip Code)
Registrant’s Telephone Number, including area code: (503) 226-4211
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
At April 28,July 31, 2006, 27,576,84627,548,346 shares of the registrant’s Common Stock $3-1/6 par value (the only class of Common Stock) were outstanding.
For the Quarterly Period Ended March 31,June 30, 2006
PART I. FINANCIAL INFORMATION
PART I. FINANCIAL INFORMATION
Consolidated Statements of Income
(Unaudited)
Three Months Ended March 31, | Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
Thousands, except per share amounts | 2006 | 2005 | 2006 | 2005 | 2006 | 2005 | ||||||||||||
Operating revenues: | ||||||||||||||||||
Gross operating revenues | $ | 390,391 | $ | 308,777 | $ | 170,979 | $ | 153,667 | $ | 561,370 | $ | 462,444 | ||||||
Less: Cost of sales | 255,399 | 180,608 | 105,036 | 92,425 | 360,435 | 273,033 | ||||||||||||
Revenue taxes | 9,528 | 7,183 | 4,196 | 3,593 | 13,724 | 10,776 | ||||||||||||
Net operating revenues | 125,464 | 120,986 | 61,747 | 57,649 | 187,211 | 178,635 | ||||||||||||
Operating expenses: | ||||||||||||||||||
Operations and maintenance | 28,247 | 27,195 | 27,909 | 26,981 | 56,156 | 54,176 | ||||||||||||
General taxes | 7,573 | 6,770 | 6,066 | 5,210 | 13,639 | 11,980 | ||||||||||||
Depreciation and amortization | 15,830 | 15,195 | 15,962 | 15,312 | 31,792 | 30,507 | ||||||||||||
Total operating expenses | 51,650 | 49,160 | 49,937 | 47,503 | 101,587 | 96,663 | ||||||||||||
Income from operations | 73,814 | 71,826 | 11,810 | 10,146 | 85,624 | 81,972 | ||||||||||||
Other income and expense - net | 518 | 65 | ||||||||||||||||
Other income and expense – net | 410 | 405 | 928 | 470 | ||||||||||||||
Interest charges - net of amounts capitalized | 9,855 | 9,128 | 9,184 | 8,906 | 19,039 | 18,034 | ||||||||||||
Income before income taxes | 64,477 | 62,763 | 3,036 | 1,645 | 67,513 | 64,408 | ||||||||||||
Income tax expense | 23,444 | 22,876 | 1,042 | 505 | 24,486 | 23,381 | ||||||||||||
Net income | $ | 41,033 | $ | 39,887 | $ | 1,994 | $ | 1,140 | $ | 43,027 | $ | 41,027 | ||||||
Average common shares outstanding: | ||||||||||||||||||
Basic | 27,584 | 27,578 | 27,563 | 27,555 | 27,574 | 27,568 | ||||||||||||
Diluted | 27,632 | 27,863 | 27,611 | 27,834 | 27,621 | 27,841 | ||||||||||||
Earnings per share of common stock: | ||||||||||||||||||
Basic | $ | 1.49 | $ | 1.45 | $ | 0.07 | $ | 0.04 | $ | 1.56 | $ | 1.49 | ||||||
Diluted | $ | 1.48 | $ | 1.43 | $ | 0.07 | $ | 0.04 | $ | 1.56 | $ | 1.48 |
See Notes to Consolidated Financial Statements
PART I. FINANCIAL INFORMATION
Consolidated Balance Sheets
Thousands | March 31, 2006 (Unaudited) | March 31, 2005 (Unaudited) | Dec. 31, 2005 | June 30, 2006 (Unaudited) | June 30, 2005 (Unaudited) | Dec. 31, 2005 | ||||||||||||||||||
Assets: | ||||||||||||||||||||||||
Plant and property: | ||||||||||||||||||||||||
Utility plant | $ | 1,890,633 | $ | 1,814,991 | $ | 1,875,444 | $ | 1,914,301 | $ | 1,835,326 | $ | 1,875,444 | ||||||||||||
Less accumulated depreciation | 547,635 | 514,785 | 536,867 | 557,632 | 523,518 | 536,867 | ||||||||||||||||||
Utility plant - net | 1,342,998 | 1,300,206 | 1,338,577 | |||||||||||||||||||||
Utility plant – net | 1,356,669 | 1,311,808 | 1,338,577 | |||||||||||||||||||||
Non-utility property | 40,953 | 34,157 | 40,836 | 41,094 | 34,862 | 40,836 | ||||||||||||||||||
Less accumulated depreciation and amortization | 6,221 | 5,408 | 5,990 | 6,452 | 5,581 | 5,990 | ||||||||||||||||||
Non-utility property - net | 34,732 | 28,749 | 34,846 | |||||||||||||||||||||
Non-utility property – net | 34,642 | 29,281 | 34,846 | |||||||||||||||||||||
Total plant and property | 1,377,730 | 1,328,955 | 1,373,423 | 1,391,311 | 1,341,089 | 1,373,423 | ||||||||||||||||||
Other investments | 54,432 | 57,198 | 58,451 | 54,962 | 57,978 | 58,451 | ||||||||||||||||||
Current assets: | ||||||||||||||||||||||||
Cash and cash equivalents | 7,522 | 2,740 | 7,143 | 6,636 | 40,343 | 7,143 | ||||||||||||||||||
Accounts receivable | 97,859 | 73,776 | 84,418 | 44,782 | 35,740 | 84,418 | ||||||||||||||||||
Accrued unbilled revenue | 47,764 | 38,880 | 81,512 | 16,657 | 17,244 | 81,512 | ||||||||||||||||||
Allowance for uncollectible accounts | (4,526 | ) | (3,499 | ) | (3,067 | ) | (3,814 | ) | (2,521 | ) | (3,067 | ) | ||||||||||||
Gas inventory | 35,906 | 23,139 | 77,256 | 76,667 | 36,547 | 77,256 | ||||||||||||||||||
Materials and supplies inventory | 9,808 | 8,262 | 8,905 | 9,546 | 9,295 | 8,905 | ||||||||||||||||||
Income taxes receivable | — | — | 13,234 | — | — | 13,234 | ||||||||||||||||||
Prepayments and other current assets | 57,330 | 21,429 | 54,309 | 47,648 | 16,048 | 54,309 | ||||||||||||||||||
Total current assets | 251,663 | 164,727 | 323,710 | 198,122 | 152,696 | 323,710 | ||||||||||||||||||
Regulatory assets: | ||||||||||||||||||||||||
Income tax asset | 66,757 | 65,622 | 65,843 | 66,757 | 65,622 | 65,843 | ||||||||||||||||||
Deferred environmental costs | 19,196 | 7,231 | 18,880 | 21,771 | 13,175 | 18,880 | ||||||||||||||||||
Deferred gas costs receivable | 13,522 | 12,978 | 6,974 | 8,594 | 7,958 | 6,974 | ||||||||||||||||||
Unamortized costs on debt redemptions | 6,776 | 7,215 | 6,881 | 6,670 | 7,097 | 6,881 | ||||||||||||||||||
Unrealized loss on non-trading derivatives | 186 | — | — | |||||||||||||||||||||
Other | — | 6,732 | — | — | 7,092 | — | ||||||||||||||||||
Total regulatory assets | 106,251 | 99,778 | 98,578 | 103,978 | 100,944 | 98,578 | ||||||||||||||||||
Other assets: | ||||||||||||||||||||||||
Fair value of non-trading derivatives | 40,879 | 88,634 | 178,653 | 26,926 | 64,089 | 178,653 | ||||||||||||||||||
Other | 9,102 | 7,305 | 9,216 | 9,448 | 7,643 | 9,216 | ||||||||||||||||||
Total other assets | 49,981 | 95,939 | 187,869 | 36,374 | 71,732 | 187,869 | ||||||||||||||||||
Total assets | $ | 1,840,057 | $ | 1,746,597 | $ | 2,042,031 | $ | 1,784,747 | $ | 1,724,439 | $ | 2,042,031 | ||||||||||||
See Notes to Consolidated Financial Statements
NORTHWEST NATURAL GAS COMPANY
PART I. FINANCIAL INFORMATION
Consolidated Balance Sheets
Thousands | March 31, 2006 (Unaudited) | March 31, 2005 (Unaudited) | Dec. 31, 2005 | June 30, 2006 (Unaudited) | June 30, 2005 (Unaudited) | Dec. 31, 2005 | ||||||||||||||||||
Capitalization and liabilities: | ||||||||||||||||||||||||
Capitalization: | ||||||||||||||||||||||||
Common stock | $ | 87,335 | $ | 87,244 | $ | 87,334 | $ | 383,103 | $ | 87,285 | $ | 87,334 | ||||||||||||
Premium on common stock | 296,281 | 299,900 | 296,471 | — | 300,074 | 296,471 | ||||||||||||||||||
Earnings invested in the business | 237,205 | 214,864 | 205,687 | 229,684 | 207,050 | 205,687 | ||||||||||||||||||
Unearned stock compensation | — | (809 | ) | (650 | ) | — | (756 | ) | (650 | ) | ||||||||||||||
Accumulated other comprehensive income (loss) | (1,911 | ) | (1,818 | ) | (1,911 | ) | (1,911 | ) | (1,818 | ) | (1,911 | ) | ||||||||||||
Total common stock equity | 618,910 | 599,381 | 586,931 | 610,876 | 591,835 | 586,931 | ||||||||||||||||||
Long-term debt | 501,500 | 483,875 | 521,500 | 492,000 | 521,500 | 521,500 | ||||||||||||||||||
Total capitalization | 1,120,410 | 1,083,256 | 1,108,431 | 1,102,876 | 1,113,335 | 1,108,431 | ||||||||||||||||||
Current liabilities: | ||||||||||||||||||||||||
Notes payable | 50,400 | 10,500 | 126,700 | 55,800 | — | 126,700 | ||||||||||||||||||
Long-term debt due within one year | 28,000 | 15,000 | 8,000 | 29,500 | 27,241 | 8,000 | ||||||||||||||||||
Accounts payable | 91,185 | 84,693 | 135,287 | 76,804 | 66,472 | 135,287 | ||||||||||||||||||
Taxes accrued | 25,876 | 22,074 | 12,725 | 13,886 | 8,543 | 12,725 | ||||||||||||||||||
Interest accrued | 11,623 | 11,171 | 2,918 | 2,878 | 2,953 | 2,918 | ||||||||||||||||||
Other current and accrued liabilities | 38,703 | 34,320 | 40,935 | 36,216 | 35,312 | 40,935 | ||||||||||||||||||
Total current liabilities | 245,787 | 177,758 | 326,565 | 215,084 | 140,521 | 326,565 | ||||||||||||||||||
Regulatory liabilities: | ||||||||||||||||||||||||
Accrued asset removal costs | 173,936 | 157,975 | 169,927 | 178,272 | 162,350 | 169,927 | ||||||||||||||||||
Unrealized gain on non-trading derivatives, net | 23,937 | 78,205 | 171,777 | — | 54,666 | 171,777 | ||||||||||||||||||
Customer advances | 1,924 | 1,592 | 1,847 | 2,113 | 1,662 | 1,847 | ||||||||||||||||||
Other | 4,283 | — | 661 | 5,744 | — | 661 | ||||||||||||||||||
Total regulatory liabilities | 204,080 | 237,772 | 344,212 | 186,129 | 218,678 | 344,212 | ||||||||||||||||||
Other liabilities: | ||||||||||||||||||||||||
Deferred income taxes | 220,568 | 206,651 | 222,331 | 220,439 | 206,666 | 222,331 | ||||||||||||||||||
Deferred investment tax credits | 4,479 | 5,155 | 5,069 | 4,422 | 5,200 | 5,069 | ||||||||||||||||||
Fair value of non-trading derivatives | 17,586 | 10,429 | 6,876 | 27,398 | 9,423 | 6,876 | ||||||||||||||||||
Other | 27,147 | 25,576 | 28,547 | 28,399 | 30,616 | 28,547 | ||||||||||||||||||
Total other liabilities | 269,780 | 247,811 | 262,823 | 280,658 | 251,905 | 262,823 | ||||||||||||||||||
Commitments and contingencies (see Note 7) | — | — | — | |||||||||||||||||||||
Commitments and contingencies (see Note 9) | — | — | — | |||||||||||||||||||||
Total capitalization and liabilities | $ | 1,840,057 | $ | 1,746,597 | $ | 2,042,031 | $ | 1,784,747 | $ | 1,724,439 | $ | 2,042,031 | ||||||||||||
See Notes to Consolidated Financial Statements
PART I. FINANCIAL INFORMATION
Consolidated Statements of Cash Flows
(Unaudited)
Three Months Ended March 31, | Six Months Ended June 30, | |||||||||||||||
Thousands | 2006 | 2005 | 2006 | 2005 | ||||||||||||
Operating activities: | ||||||||||||||||
Net income | $ | 41,033 | $ | 39,887 | $ | 43,027 | $ | 41,027 | ||||||||
Adjustments to reconcile net income to cash provided by operations: | ||||||||||||||||
Depreciation and amortization | 15,830 | 15,195 | 31,792 | 30,507 | ||||||||||||
Deferred income taxes and investment tax credits | (3,267 | ) | (5,822 | ) | (3,453 | ) | (5,762 | ) | ||||||||
Undistributed earnings from equity investments | 50 | 137 | (59 | ) | (54 | ) | ||||||||||
Allowance for funds used during construction | (133 | ) | (86 | ) | (333 | ) | (201 | ) | ||||||||
Deferred gas costs - net | (6,548 | ) | (3,427 | ) | ||||||||||||
Deferred gas costs – net | (1,620 | ) | 1,593 | |||||||||||||
Gain on sale of non-utility investments | — | (12 | ) | |||||||||||||
Contributions to qualified defined benefit pension plans | — | — | — | — | ||||||||||||
Non-cash expenses related to qualified defined benefit pension plans | 1,441 | 1,159 | 2,883 | 2,318 | ||||||||||||
Deferred environmental costs | (2,014 | ) | (230 | ) | (3,586 | ) | (805 | ) | ||||||||
Income from life insurance investments | (1,383 | ) | (452 | ) | (1,797 | ) | (974 | ) | ||||||||
Other | 4,673 | (1,790 | ) | 5,787 | (2,925 | ) | ||||||||||
Changes in working capital: | ||||||||||||||||
Accounts receivable - net | (11,982 | ) | (12,077 | ) | ||||||||||||
Accrued unbilled revenue - net | 33,748 | 25,521 | ||||||||||||||
Accounts receivable and accrued unbilled revenue - net | 105,238 | 72,138 | ||||||||||||||
Inventories of gas, materials and supplies | 40,447 | 35,076 | (52 | ) | 20,635 | |||||||||||
Income taxes receivable | 13,234 | 15,970 | 13,234 | 15,970 | ||||||||||||
Prepayments and other current assets | (2,249 | ) | 3,644 | 2,377 | 7,383 | |||||||||||
Accounts payable | (44,102 | ) | (17,785 | ) | (58,483 | ) | (36,006 | ) | ||||||||
Accrued interest and taxes | 21,856 | 20,106 | 1,121 | (1,643 | ) | |||||||||||
Other current and accrued liabilities | (2,231 | ) | 152 | (4,719 | ) | 1,144 | ||||||||||
Cash provided by operating activities | 98,403 | 115,178 | 131,357 | 144,333 | ||||||||||||
Investing activities: | ||||||||||||||||
Investment in utility plant | (15,002 | ) | (19,958 | ) | (38,991 | ) | (41,428 | ) | ||||||||
Investment in non-utility property | (106 | ) | (194 | ) | (236 | ) | (889 | ) | ||||||||
Proceeds from sale of non-utility investments | — | 3,001 | — | 3,001 | ||||||||||||
Proceeds from life insurance | 964 | — | 892 | — | ||||||||||||
Other | 1,475 | 746 | 4,453 | 679 | ||||||||||||
Cash used in investing activities | (12,669 | ) | (16,405 | ) | (33,882 | ) | (38,637 | ) | ||||||||
Financing activities: | ||||||||||||||||
Common stock issued, net of expenses | 859 | 2,569 | 1,556 | 4,669 | ||||||||||||
Common stock purchased | (398 | ) | (2,895 | ) | ||||||||||||
Common stock repurchased | (1,608 | ) | (4,861 | ) | ||||||||||||
Long-term debt issued | — | 50,000 | ||||||||||||||
Long-term debt retired | (8,000 | ) | — | |||||||||||||
Change in short-term debt | (76,300 | ) | (92,000 | ) | (70,900 | ) | (102,500 | ) | ||||||||
Cash dividend payments on common stock | (9,516 | ) | (8,955 | ) | (19,030 | ) | (17,909 | ) | ||||||||
Cash used in financing activities | (85,355 | ) | (101,281 | ) | (97,982 | ) | (70,601 | ) | ||||||||
Increase (decrease) in cash and cash equivalents | 379 | (2,508 | ) | (507 | ) | 35,095 | ||||||||||
Cash and cash equivalents - beginning of period | 7,143 | 5,248 | 7,143 | 5,248 | ||||||||||||
Cash and cash equivalents - end of period | $ | 7,522 | $ | 2,740 | $ | 6,636 | $ | 40,343 | ||||||||
Supplemental disclosure of cash flow information: | ||||||||||||||||
Interest paid | $ | 970 | $ | 970 | $ | 19,052 | $ | 17,796 | ||||||||
Income taxes paid | $ | — | $ | — | $ | 9,520 | $ | 11,739 | ||||||||
Supplemental disclosure of non-cash financing activities: | ||||||||||||||||
Conversions to common stock: | ||||||||||||||||
7-1/4% Series of Convertible Debentures | $ | — | $ | 152 | ||||||||||||
7-1/4 % Series of Convertible Debentures | $ | — | $ | 286 |
See Notes to Consolidated Financial Statements
PART I. FINANCIAL INFORMATION
Consolidated Statements of Capitalization
Thousands | March 31, 2006 (Unaudited) | March 31, 2005 (Unaudited) | Dec. 31, 2005 | June 30, 2006 (Unaudited) | June 30, 2005 (Unaudited) | Dec. 31, 2005 | ||||||||||||||||||||||||||||||||||||
Common stock equity: | ||||||||||||||||||||||||||||||||||||||||||
Common stock | $ | 87,335 | $ | 87,244 | $ | 87,334 | $ | 383,103 | $ | 87,285 | $ | 87,334 | ||||||||||||||||||||||||||||||
Premium on common stock | 296,281 | 299,900 | 296,471 | — | 300,074 | 296,471 | ||||||||||||||||||||||||||||||||||||
Earnings invested in the business | 237,205 | 214,864 | 205,687 | 229,684 | 207,050 | 205,687 | ||||||||||||||||||||||||||||||||||||
Unearned compensation | — | (809 | ) | (650 | ) | — | (756 | ) | (650 | ) | ||||||||||||||||||||||||||||||||
Accumulated other comprehensive income (loss) | (1,911 | ) | (1,818 | ) | (1,911 | ) | (1,911 | ) | (1,818 | ) | (1,911 | ) | ||||||||||||||||||||||||||||||
Total common stock equity | 618,910 | 55 | % | 599,381 | 55 | % | 586,931 | 53 | % | 610,876 | 55 | % | 591,835 | 53 | % | 586,931 | 53 | % | ||||||||||||||||||||||||
Long-term debt: | ||||||||||||||||||||||||||||||||||||||||||
Medium-Term Notes | ||||||||||||||||||||||||||||||||||||||||||
First Mortgage Bonds: | ||||||||||||||||||||||||||||||||||||||||||
6.340% Series B due 2005 | — | 5,000 | — | — | 5,000 | — | ||||||||||||||||||||||||||||||||||||
6.380% Series B due 2005 | — | 5,000 | — | — | 5,000 | — | ||||||||||||||||||||||||||||||||||||
6.450% Series B due 2005 | — | 5,000 | — | — | 5,000 | — | ||||||||||||||||||||||||||||||||||||
6.050% Series B due 2006 | 8,000 | 8,000 | 8,000 | — | 8,000 | 8,000 | ||||||||||||||||||||||||||||||||||||
6.310% Series B due 2007 | 20,000 | 20,000 | 20,000 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||||||||||||||||||||
6.800% Series B due 2007 | 9,500 | 9,500 | 9,500 | 9,500 | 9,500 | 9,500 | ||||||||||||||||||||||||||||||||||||
6.500% Series B due 2008 | 5,000 | 5,000 | 5,000 | 5,000 | 5,000 | 5,000 | ||||||||||||||||||||||||||||||||||||
4.110% Series B due 2010 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||||||||||||||||||||
7.450% Series B due 2010 | 25,000 | 25,000 | 25,000 | 25,000 | 25,000 | 25,000 | ||||||||||||||||||||||||||||||||||||
6.665% Series B due 2011 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||||||||||||||||||||
7.130% Series B due 2012 | 40,000 | 40,000 | 40,000 | 40,000 | 40,000 | 40,000 | ||||||||||||||||||||||||||||||||||||
8.260% Series B due 2014 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||||||||||||||||||||
4.700% Series B due 2015 | 40,000 | — | 40,000 | 40,000 | 40,000 | 40,000 | ||||||||||||||||||||||||||||||||||||
7.000% Series B due 2017 | 40,000 | 40,000 | 40,000 | 40,000 | 40,000 | 40,000 | ||||||||||||||||||||||||||||||||||||
6.600% Series B due 2018 | 22,000 | 22,000 | 22,000 | 22,000 | 22,000 | 22,000 | ||||||||||||||||||||||||||||||||||||
8.310% Series B due 2019 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||||||||||||||||||||
7.630% Series B due 2019 | 20,000 | 20,000 | 20,000 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||||||||||||||||||||
9.050% Series A due 2021 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||||||||||||||||||||
5.620% Series B due 2023 | 40,000 | 40,000 | 40,000 | 40,000 | 40,000 | 40,000 | ||||||||||||||||||||||||||||||||||||
7.720% Series B due 2025 | 20,000 | 20,000 | 20,000 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||||||||||||||||||||
6.520% Series B due 2025 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||||||||||||||||||||
7.050% Series B due 2026 | 20,000 | 20,000 | 20,000 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||||||||||||||||||||
7.000% Series B due 2027 | 20,000 | 20,000 | 20,000 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||||||||||||||||||||
6.650% Series B due 2027 | 20,000 | 20,000 | 20,000 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||||||||||||||||||||
6.650% Series B due 2028 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||||||||||||||||||||
7.740% Series B due 2030 | 20,000 | 20,000 | 20,000 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||||||||||||||||||||
7.850% Series B due 2030 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||||||||||||||||||||
5.820% Series B due 2032 | 30,000 | 30,000 | 30,000 | 30,000 | 30,000 | 30,000 | ||||||||||||||||||||||||||||||||||||
5.660% Series B due 2033 | 40,000 | 40,000 | 40,000 | 40,000 | 40,000 | 40,000 | ||||||||||||||||||||||||||||||||||||
5.250% Series B due 2035 | 10,000 | — | 10,000 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||||||||||||||||||||
Convertible Debentures | ||||||||||||||||||||||||||||||||||||||||||
7-1/4% Series due 2012 | — | 4,375 | — | — | 4,241 | — | ||||||||||||||||||||||||||||||||||||
529,500 | 498,875 | 529,500 | 521,500 | 548,741 | 529,500 | |||||||||||||||||||||||||||||||||||||
Less long-term debt due within one year | 28,000 | 15,000 | 8,000 | 29,500 | 27,241 | 8,000 | ||||||||||||||||||||||||||||||||||||
Total long-term debt | 501,500 | 45 | % | 483,875 | 45 | % | 521,500 | 47 | % | 492,000 | 45 | % | 521,500 | 47 | % | 521,500 | 47 | % | ||||||||||||||||||||||||
Total capitalization | $ | 1,120,410 | 100 | % | $ | 1,083,256 | 100 | % | $ | 1,108,431 | 100 | % | $ | 1,102,876 | 100 | % | $ | 1,113,335 | 100 | % | $ | 1,108,431 | 100 | % | ||||||||||||||||||
See Notes to Consolidated Financial Statements
PART I. FINANCIAL INFORMATION
Notes to Consolidated Financial Statements
(Unaudited)
1. | Basis of Financial Statements |
The consolidated financial statements include the accounts of Northwest Natural Gas Company (NW Natural), a regulated utility, and its non-regulated wholly-owned subsidiary business, NNG Financial Corporation (Financial Corporation).
The information presented in the interim consolidated financial statements is unaudited, but includes all material adjustments, including normal recurring accruals, that the management of the Company considers necessary for a fair statement of the results for each period reported. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in the Company’sour 2005 Annual Report on Form 10-K (2005 Form 10-K). A significant part of theour business of the Company is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of the results for a full year.
Certain amounts from prior years have been reclassified to conform, for comparison purposes, with the current financial statement presentation. The current year’s presentation of the Consolidated Statements of Income includes the reclassification of revenue taxes as a component of net operating revenues. Revenue taxes are expenses primarily related to the utility’s franchise agreements and are based on gross operating revenues. Since revenue taxes are a direct cost of utility sales, the financial statement classification was changed to improve the presentation of net operating revenues and operating expenses. In prior years, revenue taxes were included under operating expenses as part of taxes other than income taxes. The reclassifications had no impact on the prior years’year’s income from operations or net income.
2. | New Accounting Standards |
Adopted Standards
Share Based Payment. Effective Jan. 1, 2006, we adopted Statement of Financial Accounting Standards (SFAS) No. 123R, “Share Based Payment,” using the Modified Prospective Application method without restatement of prior periods. Prior to implementation of SFAS No. 123R, the Companywe accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123R requires companies to recognize compensation expense for all equity-based compensation awards issued to employees that are expected to vest. Under this method, the Companywe began to amortize compensation cost for the remaining portion of outstanding awards for which the requisite service was not yet rendered at Jan. 1, 2006. Compensation cost for these awards was based on the fair value of the awards at the grant date aswhich was determined under the intrinsic value method. The Company willWe determine the fair value of and account for awards that are granted, modified or settled after Jan. 1, 2006 in accordance with SFAS No. 123R. The adoption of SFAS No. 123R did not have a material impact on the Company’sour financial condition, results of operations or cash flows. See Note 34 for a detailed discussion of stock-based compensation.
Accounting for Changes and Error Corrections.Effective Jan. 1, 2006, we adopted SFAS No. 154, “Accounting for Changes and Error Corrections – a replacement of APB Opinion No. 20 and FASB Statement No. 3,” which provides guidance on the accounting for and reporting of accounting changes and error corrections. The statement requires retrospective application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable
to determine the period-specific effects or the cumulative effect of the change. The guidance provided in APB Opinion No. 20 for reporting the correction of an error in previously issued financial statements remains unchanged and requires the restatement of previously issued financial statements. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after Dec. 15, 2005. The adoption of SFAS No. 154 did not have a material impact upon the Company’sNW Natural’s financial condition, results of operation or cash flows.
Inventory Costs. Effective Jan. 1, 2006, we adopted SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4,” which amends the guidance on inventory pricing to require that abnormal amounts of idle facility expense, freight, handling costs and wasted material be charged to current period expense rather than capitalized as inventory costs. The adoption of SFAS No. 151 did not have a material impact upon the Company’son NW Natural’s financial condition, results of operations or cash flows.
Recent Accounting Pronouncements
Purchases and Sales of Inventory with the Same Counterparty. In September 2005, the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force (EITF) reached a final consensus on Issue 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF 04-13 requires that two or more legally separate exchange transactions with the same counterparty be combined and considered a single arrangement for purposes of applying APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” when the transactions are entered into in contemplation of one another. EITF 04-13 is effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. Adoption of this standard isdid not expected to have a material impact on the Company’sNW Natural’s financial condition, results of operations or cash flows.
Recent Accounting Pronouncements
Accounting for Certain Hybrid Instruments.In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Instruments,” which amends SFAS Nos. 133 and 140. SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for as a whole if the holder elects to account for the whole instrument on a fair value basis. The statement is effective for all financial instruments acquired or issued after Jan. 1, 2007. The Company isWe are in the process of evaluating the effect of the adoption and implementation of SFAS No. 155, which is not expected to have a material impact on itsour financial condition, results of operation or cash flows.
Variable Interest Entities.In April 2006, the FASB issued a staff position (FSP) interpreting variable interest entities (VIE) under FASB Interpretation No. (FIN) 46(R)-6, “Determining the Variability to be Considered in Applying FIN 46(R)-6..” This staff position emphasizes that preparers should use a “by design” approach in determining whether an interest is variable. A “by design” approach includes evaluating whether an interest is variable based on a thorough understanding of the design of the potential VIE, including the nature of the risks that the potential VIE was designed to create and pass along to interest holders in the entity. Consolidation of a VIE by the primary beneficiary is required if it is determined that the VIE does not effectively disperse risks among the parties involved. FSP No. FIN 46(R)-6 must be applied prospectively to all entities with which the Companycompany first becomes involved and to all entities previously required to be analyzed under FIN 46(R) when a reconsideration event has occurred effective on or after July 1, 2006. The Company isWe are in the process of evaluating the effect of adoption and implementation of FSP No. FIN 46(R)-6, which is not expected to have a material impact on itsour financial condition, results of operations or cash flows.
Accounting for Uncertainty in Income Taxes.In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB
Statement No. 109,” (FIN 48). FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken in a tax return. We must determine whether it is “more-likely-than-not” that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. Once it is determined that a position meets the more-likely-than-not recognition threshold, the position is measured to determine the amount of benefit to recognize in the financial statements. FIN 48 applies to all tax positions related to income taxes subject to SFAS No. 109, “Accounting for Income Taxes.” The interpretation scopes out income tax positions related to SFAS No. 5, “Accounting for Contingencies.” FIN 48 is effective for fiscal years beginning after Dec. 15, 2006. We do not anticipate that the adoption of this statement will have a material effect on our financial position or results of operations.
3. | Capital Stock |
At NW Natural’s Annual Meeting held on May 25, 2006, the shareholders approved the Restated Articles of Incorporation, which, among other things, included an amendment, effective May 31, 2006, to eliminate the par value of NW Natural’s common stock. As a result, NW Natural’s “common stock” and “premium on common stock” account balances are now reflected on the balance sheet as “common stock.”
In addition, the shareholders approved an amendment to the Employee Stock Purchase Plan that reserved an additional 200,000 shares of common stock for issuance under the plan.
4. | Stock-Based Compensation |
Effective Jan. 1, 2006, we adopted SFAS No. 123R, “Share Based Payment,” to account for all stock-based compensation plans. Our stock-based compensation plans consist of the Long-Term Incentive Plan (LTIP), the Restated Stock Option Plan (Restated SOP), the Employee Stock Purchase Plan (ESPP) and the Non-Employee Directors Stock Compensation Plan (NEDSCP). These plans are designed to promote stock ownership in NW Natural by employees and officers, and, in the case of the NEDSCP, non-employee directors. See Part II, Item 8., Note 4, in the 2005 Form 10-K for a discussion of the Company’sNW Natural’s stock-based compensation plans.
Long-Term Incentive Plan. A total of 500,000 shares of the Company’sNW Natural’s common stock has been authorized for awards under the terms of the LTIP as stock bonus, restricted stock or performance-based stock awards. At March 31,June 30, 2006, performance-based awards on 105,000 shares, based on target, were outstanding, a restricted stock award for 5,000 shares was outstanding, and the remaining 390,000 shares arewere available for future grants.
Performance-based Stock Awards.At March 31,June 30, 2006, the aggregate number of performance-based shares awarded and outstanding under the Company’sNW Natural’s LTIP at the threshold, target and maximum levels were as follows:
Year Awarded | Performance Period | Threshold | Target | Maximum | Performance Period | Threshold | Target | Maximum | ||||||||
2004 | 2004-06 | 6,750 | 27,000 | 54,000 | 2004-06 | 6,750 | 27,000 | 54,000 | ||||||||
2005 | 2005-07 | 8,750 | 35,000 | 70,000 | 2005-07 | 8,750 | 35,000 | 70,000 | ||||||||
2006 | 2006-08 | 10,750 | 43,000 | 86,000 | 2006-08 | 10,750 | 43,000 | 86,000 | ||||||||
Total | 26,250 | 105,000 | 210,000 | |||||||||||||
Total | 26,250 | 105,000 | 210,000 | |||||||||||||
For each of the performance periods shown above, awards will be based on total shareholder return relative to a peer group of gas distribution companies over the three-year performance period and on performance results relative to the Company’sour core and non-core strategies. For awards granted prior to Jan. 1, 2006, the Company recognizeswe recognize compensation expense and liability for the LTIP
awards based on performance levels achieved, and expected to be achieved, and the estimated market value of the common stock as of the distribution date. For awards granted on or after Jan. 1, 2006, the Company recognizeswe recognize compensation expense in accordance with SFAS No. 123R, based on performance levels achieved and an estimated fair value using a lattice valuation model. For the quarter and six months ended March 31,June 30, 2006, the amount accrued and expensed as compensation under the three LTIP grants was negligible. On a cumulative basis, $0.7 million, $0.6 million and a negligible amount have been accrued for the 2004-06, 2005-07 and 2006-08 performance periods, respectively.
Restricted Stock Awards.Restricted stock awards also have been granted under the LTIP. A restricted stock award consisting of 5,000 shares was granted in 2004, which will vest ratably over the period 2005-09.
Restated Stock Option Plan. The Company hasWe have reserved a total of 2,400,000 shares of Common Stock for issuance under the Restated SOP. At March 31,June 30, 2006, options on 1,132,6001,134,400 shares were available for grant and options to purchase 393,700388,750 shares were outstanding at March 31, 2006.outstanding. Options are granted with an exercise price equal to the market value of the common stock at the date of grant, have 10-year terms and vest ratably over a threethree- or four-year period following the date of grant. Shares issued under the Restated SOP upon the exercise of stock options are original issue shares. The fair value of the Company’sour stock-based awards were estimated as of the date of grant using the Black-Scholes option pricing model based on the following weighted-average assumptions:
2006 | 2005 | |||||
Risk-free interest rate | 4.5 | % | 4.2 | % | ||
Expected life (in years) | 6.2 | 7.0 | ||||
Expected market price volatility factor | 22.8 | % | 24.6 | % | ||
Expected dividend yield | 4.0 | % | 3.6 | % |
The simplified formula for “plain vanilla” options was utilized to determine the expected life as defined and permitted by Staff Accounting Bulletin No. 107. The risk-free interest rate was based on the implied yield currently available on U.S. Treasury zero-coupon issues with a life equal to the expected life of the options. Historical data was employed in order to estimate the volatility factor, measured on a daily basis, for a period equal to the duration of the expected life of the option awards. The dividend yield was based on management’s current estimate for dividend payout at the time of grant. A forfeiture rate of 3 percent was applied to the calculation of compensation expense.expense based on historical experience.
The following table presents the effect on net income and earnings per share forof outstanding stock options and stock awards prior to the adoption of SFAS No. 123R for the quarter ended March 31, 2005 in addition to the impact on reported earnings in the quarter ended March 31, 2006:awards:
Pro Forma Effect of Stock-Based Options and ESPP: Thousands, except per share amounts | Three Months Ended March 31, | |||||||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||
Pro Forma Effect of Stock-Based Options and ESPP: Thousands, except per share amounts | 2006 | 2005 | 2006 | 2005 | 2006 | 2005 | ||||||||||||||||
$ | 41,033 | $ | 39,887 | N/A | * | $ | 1,140 | N/A | * | $ | 41,027 | |||||||||||
Add: Actual stock-based compensation expense included in reported net income under SFAS No. 123R, net of related tax effects | 193 | — | — | — | ||||||||||||||||||
Deduct: Pro forma stock-based compensation expense determined under the fair value based method, net of related tax effects | (193 | ) | (92 | ) | ||||||||||||||||||
Deduct: Pro forma stock-based compensation expense determined under the fair value based method — net of related tax effects | (92 | ) | (183 | ) | ||||||||||||||||||
Pro forma earnings applicable to common stock - basic | 41,033 | 39,795 | 1,048 | 40,844 | ||||||||||||||||||
Debenture interest less taxes | — | 48 | 47 | 94 | ||||||||||||||||||
Pro-forma earnings applicable to common stock - diluted | $ | 41,033 | $ | 39,843 | $ | 1,095 | $ | 40,938 | ||||||||||||||
Basic earnings per share | ||||||||||||||||||||||
As reported | $ | 1.49 | $ | 1.45 | $ | 0.04 | $ | 1.49 | ||||||||||||||
Pro forma | $ | 1.49 | $ | 1.44 | $ | 0.04 | $ | 1.48 | ||||||||||||||
Diluted earnings per share | ||||||||||||||||||||||
As reported | $ | 1.48 | $ | 1.43 | $ | 0.04 | $ | 1.48 | ||||||||||||||
Pro forma | $ | 1.48 | $ | 1.43 | $ | 0.04 | $ | 1.47 |
* | During 2006, we implemented SFAS No. 123R and, therefore, pro forma is as reported. |
Summarized information for stock option grants is as follows:
Price per Share | Price per Share | ||||||||||||||||
Option Shares | Range | Weighted-Average Exercise Price | Option Shares | Range | Weighted-Average Exercise Price | ||||||||||||
Balance Outstanding, Dec. 31, 2004 | 431,470 | $ | 20.25-32.02 | $ | 28.38 | ||||||||||||
Balance Outstanding at Dec. 31, 2005 | 308,500 | $20.25-38.30 | $ | 29.26 | |||||||||||||
Granted | 9,000 | 34.95-38.30 | 37.18 | 97,800 | 34.29 | 34.29 | |||||||||||
Exercised | (121,170 | ) | 20.25-31.34 | 26.59 | (15,150 | ) | 20.25-31.34 | 25.97 | |||||||||
Expired | (10,800 | ) | 27.60-31.34 | 30.79 | (2,400 | ) | 31.34 | 32.82 | |||||||||
Balance Outstanding, Dec. 31, 2005 | 308,500 | $ | 20.25-38.30 | $ | 29.26 | ||||||||||||
Balance Outstanding at June 30, 2006 | 388,750 | $20.25-38.30 | $ | 30.63 | |||||||||||||
Granted | 97,800 | 34.29 | 34.29 | ||||||||||||||
Exercised | (12,000 | ) | 20.25-31.34 | 24.55 | |||||||||||||
Expired | (600 | ) | 31.34 | 31.34 | |||||||||||||
Balance Outstanding, Mar. 31, 2006 | 393,700 | $ | 20.25-38.30 | $ | 30.65 | ||||||||||||
Exercisable, Dec. 31, 2005 | 189,500 | $ | 20.25-32.02 | $ | 27.63 | ||||||||||||
Exercisable, Mar. 31, 2006 | 232,850 | $ | 20.25-32.02 | $ | 28.67 | ||||||||||||
Exercisable at Dec. 31, 2005 | 189,500 | $20.25-32.02 | $ | 27.63 | |||||||||||||
Exercisable at June 30, 2006 | 230,850 | $20.25-32.02 | $ | 28.66 |
The weighted-average grant-date fair value of equity awards granted during 2005 and 2006 was $7.85 and $6.29, respectively. By Dec. 31, 2006, an additional 3,000 shares will vest for a total of 235,850233,850 exercisable shares at year-end.year-end, assuming no forfeitures.
During the first quarter ofthree and six months ended June 30, 2006, $0.2 million of pre-tax compensation expense relatedamounted to $0.2 million and $0.4 million, respectively, relating to options granted under the Restated SOPSOP. This expense was recognized in incomeoperations and maintenance expense under the fair value method in accordance with SFAS No. 123R. In addition, less than $0.1 million of pre-tax compensation expense related to the Employee Stock Purchase PlanESPP was recognized. As of March 31,June 30, 2006, there was $0.8$0.7 million of unrecognized compensation cost related to the unvested portion of outstanding stock option awards expected to be recognized over a period extending through 2009.
In the first quarter ofsix months ended June 30, 2006, 12,000 options15,150 option shares were exercised with a total intrinsic value of $0.1 million. Cash of $0.3$0.4 million was received for these exercises, and a negligible
related tax benefit was realized. The total intrinsic value of options exercised in the first quartersix months of 2005 was $0.6$1.0 million, and the total fair value of options that vested in the first quarterssix months of 2006 and 2005 was $0.3 million and $0.4 million, respectively.
The following table summarizes additional information about stock options outstanding and exercisable at March 31,June 30, 2006:
Outstanding | Exercisable | Outstanding | Exercisable | |||||||||||||||||||||||||||
Range of Exercise Prices | Stock Options | (In millions) Aggregate Intrinsic Value | Stock Options | (In millions) Aggregate Intrinsic Value | Weighted- Exercise Price | Weighted- Remaining Life in Years | Stock Options | (In millions) Aggregate Intrinsic Value | Stock Options | (In millions) Aggregate Intrinsic Value | Weighted- Average Exercise Price | Weighted- Average Remaining Life in Years | ||||||||||||||||||
$20.25 - $38.30 | 393,700 | $ | 1.7 | 232,850 | $ | 1.4 | $ | 28.67 | 6.3 | |||||||||||||||||||||
$20.25 - 38.30 | 388,750 | $ | 1.6 | 230,850 | $ | 1.4 | $ | 28.66 | 6.1 |
Long-Term Debt |
In June 2006, NW Natural redeemed $8.0 million of secured 6.05% Series B Medium-Term Notes, at maturity.
6. | Use of Derivative Instruments |
NW Natural enters into forward contracts and other related financial transactions for the purchase of natural gas that qualify as derivative instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149 (collectively referred to as SFAS No. 133). NW Natural utilizes derivative financial instruments to manage commodity prices related to natural gas supply requirements (see Part II, Item 8., Note 11, in the 2005 Form 10-K).
At March 31,June 30, 2006 and 2005, unrealized gains or losses from mark-to-market valuations of the Company’sour derivative instruments were primarily reported as regulatory liabilities or regulatory assets because regulatory mechanisms provide for the realized gains or losses at settlement to be included in utility gas costs, subjectpursuant to regulatory deferral treatment. The estimated fair values for unrealized gains and losses on derivative instruments outstanding, determined using a discounted cash flow model, for financial swaps and physical derivatives, were as follows:
Fair Value Gains (Losses) | ||||||||||||||||||||||||
March 31, | Dec. 31, | June 30, | Dec. 31, 2005 | |||||||||||||||||||||
Thousands | 2006 | 2005 | 2005 | 2006 | 2005 | |||||||||||||||||||
Fair Value Gain (Loss) | ||||||||||||||||||||||||
Fair Value Gain (Loss): | ||||||||||||||||||||||||
Natural gas commodity-based derivative instruments: | ||||||||||||||||||||||||
Fixed-price financial swaps | $ | 26,405 | $ | 87,995 | $ | 173,790 | $ | 1,853 | $ | 62,464 | $ | 173,790 | ||||||||||||
Fixed-price financial call options | — | — | 1,871 | — | — | 1,871 | ||||||||||||||||||
Indexed-price physical supply | (3,079 | ) | (8,483 | ) | (5,454 | ) | (2,571 | ) | (7,887 | ) | (5,454 | ) | ||||||||||||
Fixed-price physical supply | — | (1,429 | ) | 820 | — | — | 820 | |||||||||||||||||
Physical supply contracts with embedded options | 566 | — | 567 | 335 | 43 | 567 | ||||||||||||||||||
Foreign currency forward purchases | 45 | 122 | 183 | 197 | 46 | 183 | ||||||||||||||||||
Total | $ | 23,937 | $ | 78,205 | $ | 171,777 | $ | (186 | ) | $ | 54,666 | $ | 171,777 | |||||||||||
In the firstsecond quarter of 2006, NW Natural realized net gainslosses of $17.5$10.5 million from the settlement of natural gas commodityfixed-price financial swap and call option contracts, which were recorded as decreases to the cost of gas. Realized losses were offset by lower gas purchase costs from underlying floating rate physical supply contracts. The currency exchange rate in all foreign currency forward purchase contracts is included in our cost of gas at settlement; therefore, no gain or loss was recorded from the settlement of those contracts.
As of March 31,June 30, 2006, all natural gas commodity price swap contracts mature no later than Oct. 31, 2008.
Segment Information |
The Company’sOur primary business segment, “Utility,” consists of the distribution and sale of natural gas. Another segment, “Interstate Gas Storage,” represents natural gas storage services provided to interstate and intrastate customers and asset optimization activities performed by an unaffiliated energy marketing company primarily through the use of commodity transactions and releases of temporarily unused portions of NW Natural’s upstream pipeline transportation capacity and gas storage capacity (see Part II, Item 8., Note 2, in the 2005 Form 10-K). The remaining segment, “Other,” primarily consists of non-utility operating activities and non-regulated investments.
The following table presents information about the reportable segments for the three-month periods ended March 31, 2006 and 2005.segments. Inter-segment transactions are insignificant.
Three Months Ended March 31, | Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||||||||||
Thousands | Utility | Interstate Gas Storage | Other | Total | Utility | Interstate Gas Storage | Other | Total | Utility | Interstate Gas Storage | Other | Total | |||||||||||||||||||||||||||
2006 | |||||||||||||||||||||||||||||||||||||||
Net operating revenues | $ | 122,344 | $ | 3,079 | $ | 41 | $ | 125,464 | $ | 58,047 | $ | 3,671 | $ | 29 | $ | 61,747 | $ | 180,391 | $ | 6,750 | $ | 70 | $ | 187,211 | |||||||||||||||
Depreciation and amortization | 15,610 | 220 | — | 15,830 | 15,742 | 220 | — | 15,962 | 31,352 | 440 | — | 31,792 | |||||||||||||||||||||||||||
Income from operations | 71,122 | 2,684 | 8 | 73,814 | |||||||||||||||||||||||||||||||||||
Income (loss) from financial investments | 1,383 | — | (50 | ) | 1,333 | ||||||||||||||||||||||||||||||||||
Net income | 39,452 | 1,449 | 132 | 41,033 | |||||||||||||||||||||||||||||||||||
Total assets at March 31, 2006 | 1,792,955 | 35,533 | 11,569 | 1,840,057 | |||||||||||||||||||||||||||||||||||
Income (loss) from operations | 8,992 | 3,249 | (431 | ) | 11,810 | 80,114 | 5,933 | (423 | ) | 85,624 | |||||||||||||||||||||||||||||
Income from financial investments | 414 | — | 109 | 523 | 1,797 | — | 59 | 1,856 | |||||||||||||||||||||||||||||||
Net income (loss) | 214 | 1,817 | (37 | ) | 1,994 | 39,666 | 3,266 | 95 | 43,027 | ||||||||||||||||||||||||||||||
Total assets at June 30, 2006 | 1,737,026 | 36,084 | 11,637 | 1,784,747 | 1,737,026 | 36,084 | 11,637 | 1,784,747 | |||||||||||||||||||||||||||||||
2005 | |||||||||||||||||||||||||||||||||||||||
Net operating revenues | $ | 118,936 | $ | 2,029 | $ | 21 | $ | 120,986 | $ | 55,676 | $ | 1,952 | $ | 21 | $ | 57,649 | $ | 174,612 | $ | 3,981 | $ | 42 | $ | 178,635 | |||||||||||||||
Depreciation and amortization | 15,031 | 164 | — | 15,195 | 15,149 | 163 | — | 15,312 | 30,180 | 327 | — | 30,507 | |||||||||||||||||||||||||||
Income (loss) from operations | 70,168 | 1,693 | (35 | ) | 71,826 | 8,559 | 1,587 | — | 10,146 | 78,727 | 3,280 | (35 | ) | 81,972 | |||||||||||||||||||||||||
Income (loss) from financial investments | 468 | — | (137 | ) | 331 | ||||||||||||||||||||||||||||||||||
Income from financial investments | 506 | — | 208 | 714 | 974 | — | 71 | 1,045 | |||||||||||||||||||||||||||||||
Net income | 38,844 | 898 | 145 | 39,887 | 12 | 844 | 284 | 1,140 | 38,856 | 1,742 | 429 | 41,027 | |||||||||||||||||||||||||||
Total assets at March 31, 2005 | 1,707,832 | 28,331 | 10,434 | 1,746,597 | |||||||||||||||||||||||||||||||||||
Total assets at June 30, 2005 | 1,682,429 | 29,424 | 12,586 | 1,724,439 | 1,682,429 | 29,424 | 12,586 | 1,724,439 |
Pension and Other Postretirement Benefits |
Net Periodic Benefit Cost
The following table provides the components of net periodic benefit cost for the qualified and non-qualified pension plans and other postretirement benefit plans for the three months ended March 31, 2006 and 2005.plans. See Part II, Item 8., Note 7, in the 2005 Form 10-K for a discussion of the assumptions used in measuring these costs and benefit obligations.
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
Three Months Ended June 30, | ||||||||||||||||||||||||||||
Thousands | Pension Benefits | Other Postretirement Benefits | 2006 | 2005 | 2006 | 2005 | ||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||||||
2006 | 2005 | 2006 | 2005 | |||||||||||||||||||||||||
Service cost | $ | 1,961 | $ | 1,589 | $ | 137 | $ | 114 | $ | 1,961 | $ | 1,589 | $ | 138 | $ | 114 | ||||||||||||
Interest cost | 3,758 | 3,263 | 283 | 308 | 3,758 | 3,263 | 283 | 308 | ||||||||||||||||||||
Special termination benefits | — | 63 | — | — | — | 63 | — | — | ||||||||||||||||||||
Expected return on plan assets | (4,403 | ) | (3,530 | ) | — | — | (4,403 | ) | (3,531 | ) | — | — | ||||||||||||||||
Amortization of transition obligation | — | — | 103 | 103 | — | — | 103 | 103 | ||||||||||||||||||||
Amortization of prior service cost | 245 | 223 | 49 | — | 245 | 223 | 49 | — | ||||||||||||||||||||
Recognized actuarial loss | 916 | 481 | — | 72 | 916 | 481 | — | 72 | ||||||||||||||||||||
Net periodic benefit cost | $ | 2,477 | $ | 2,089 | $ | 572 | $ | 597 | $ | 2,477 | $ | 2,088 | $ | 573 | $ | 597 | ||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
Six Months Ended June 30, | ||||||||||||||||||||||||||||
Thousands | 2006 | 2005 | 2006 | 2005 | ||||||||||||||||||||||||
Service cost | $ | 3,922 | $ | 3,177 | $ | 275 | $ | 228 | ||||||||||||||||||||
Interest cost | 7,516 | 6,526 | 566 | 616 | ||||||||||||||||||||||||
Special termination benefits | — | 126 | — | — | ||||||||||||||||||||||||
Expected return on plan assets | (8,807 | ) | (7,061 | ) | — | — | ||||||||||||||||||||||
Amortization of transition obligation | — | — | 206 | 206 | ||||||||||||||||||||||||
Amortization of prior service cost | 490 | 446 | 98 | — | ||||||||||||||||||||||||
Recognized actuarial loss | 1,833 | 963 | — | 144 | ||||||||||||||||||||||||
Net periodic benefit cost | $ | 4,954 | $ | 4,177 | $ | 1,145 | $ | 1,194 | ||||||||||||||||||||
Employer Contributions
The Company isWe are not required to make cash contributions to itsour qualified non-contributory defined benefit plans in 2006, but cash contributions in the form of ongoing benefit payments will be required for itsthe unfunded non-qualified supplemental pension plans and other postretirement benefit plans in 2006. See Part II, Item 8., Note 7, in the 2005 Form 10-K for a discussion of future payments.
Commitments and Contingencies |
Environmental Matters
NW Natural owns,We own, or hashave previously owned, properties that may require environmental remediation or action. NW Natural accruesWe accrue all material loss contingencies relating to these properties that it believeswe believe to be probable of assertion and reasonably estimable. The Company continuesWe continue to study the extent of its potential environmental liabilities, but due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several environmental site investigations, the range of potential loss beyond the amounts currently accrued, and the
probabilities thereof, cannot be reasonably estimated. NW NaturalWe regularly reviews itsreview our remediation liability for each site where itwe may be exposed to remediation responsibilities. The costs of environmental remediation are difficult to estimate. A number of steps are involved in each environmental remediation effort, including site investigations, remediation, operations and maintenance, monitoring and site closure. Each of these steps may, over time, involve a number of alternative actions, each of which can change the course of the effort. In certain cases, in addition to NW Natural, there are a number of other potentially responsible parties, each of which, in proceedings and negotiations with other potentially responsible parties and regulators, may influence the course of the remediation effort. The allocation of liabilities among the potentially responsible parties is often subject to dispute and highly uncertain. The events giving rise to environmental liabilities often occurred many decades ago, which complicates the determination of allocating liabilities among potentially responsible
parties. Site investigations and remediation efforts often develop slowly over many years. To the extent reasonably estimable, NW Natural estimateswe estimate the costs of environmental liabilities using current technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a bettermore likely estimate within this range of probable cost, NW Natural recordswe record the liability at the lower end of this range. It is likely that changes in these estimates will occur throughout the remediation process for each of these sites due to uncertainty concerning NW Natural’sour responsibility, the complexity of environmental laws and regulations and the selection of compliance alternatives. The status of each of the sites currently under investigation is provided below. Also, see Part II, Item 8., Note 12, in the 2005 Form 10-K for a description of these properties and further discussion.
Gasco site. NW Natural ownsWe own property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (the Gasco site). TheWe have been investigating the Gasco site has been under investigation by NW Natural for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, the Companywe filed a Feasibility Scoping Plan and an Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of remedial alternatives for the most contaminated portion of the Gasco site. In the firstsecond quarter of 2006, NW Naturalwe accrued an additional $0.2$2.1 million for the estimated cost of wells to be used as partfor the upgrade of the water treatment system in conjunction with source control, replacement of a pilot studywell, ongoing consultant and investigation fees for in-river groundwater and source control.control studies and to cover cost estimates of remedial alternatives identified in the Feasibility Scoping Plan and Ecological and Human Health risk assessment for the most contaminated portion of the site. The liability of $1.1balance at June 30, 2006 is $2.6 million, for the Gasco sitewhich is at the low end of the range because no amount within the range is consideredprobable and reasonably estimable liability range. We are not able to be more likely than another andestimate the high end of the range cannot be estimated.a liability range.
Siltronic (formerly Wacker) site. NW NaturalWe previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation (formerly Wacker Siltronic Corporation) (the Siltronic site). The liability balance for this site at March 31, 2006We have agreed to an addendum to the Voluntary Clean-up Agreement with the ODEQ, which will require additional investigation of manufactured gas plant waste on the Siltronic site. Since the scope of work is negligible (see “Regulatory and Insurance Recovery for Environmental Matters,” below).unknown, there is not enough information to reasonably estimate the additional liabilities.
Portland Harbor site. In 1998, the ODEQ and the U.S. Environmental Protection Agency (EPA) completed a study of sediments in a 5.5-mile segment of the Willamette River (the Portland Harbor) that includes the area adjacent to the Gasco site and the Siltronic site. The Portland Harbor was listed by the EPA as a Superfund site in 2000 and the Company waswe were notified that it iswe are a potentially responsible party. Subsequently, the EPA approved a Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor Remedial Investigation/Feasibility Study (RI/FS). Current informationIn the second quarter of 2006, we increased the liability by $0.2 million to $1.6 million in total for our current estimate of liability related to the RI/FS, consultant fees, technical work, and state settlement agreement. Information is not sufficient to
reasonably estimate additional liabilities, if any, or the range of potential liabilities, for environmental remediation and monitoring after the RI/FS work plan is completed, except for the early action removal of a tar deposit in the river sediments discussed below.
In April 2004, the Companywe entered into an Administrative Order on Consent providing for early action removal of a deposit of tar in the riverWillamette River sediments adjacent to the Gasco site. NW Natural completed theThe removal of the tar deposit in the Portland Harbor was completed in October 2005, and on Nov. 5,in November 2005, the EPA approved the completed project. The estimatedIn the second quarter of 2006, we increased the liability by $0.2 million to $1.4 million for our current remaining cost forestimate related to the removal,tar deposit, including technical work, oversight, consultants,consultant and legal fees and ongoing monitoring is $10 million. To-date, NW Naturalmonitoring. To date, $8.8 million has been spent $8.1 million for work related to the removal of the tar deposit with a remaining estimated liability of $1.9 million.deposit.
Oregon Steel Mills site. See “Legal Proceedings,” below.
Regulatory and Insurance Recovery for Environmental Matters. In May 2003, the Oregon Public Utility Commission (OPUC) approved NW Natural’sour request for deferral of environmental costs associated with specific sites, including the Gasco, Siltronic and Portland Harbor sites. The authorization, which has been extended through January 2007, and expanded to include the Oregon Steel Mills site, allows NW Naturalus to defer and seek recovery of unreimbursed environmental costs in a future general rate case. In April 2006, the OPUC authorized NW Naturalus to accrue interest on deferred balances effective Jan. 27, 2006, subject to an annual demonstration to the OPUC that the Company haswe have maximized itsour insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. As of March 31,June 30, 2006, the Company haswe have paid a cumulative total of $14.4$16.0 million relating to the named sites since the effective date of the deferral authorization.
On a cumulative basis, NW Natural haswe have recognized a total of $24.0$26.6 million for environmental costs, including legal, investigation, monitoring and remediation costs. Of this total, $19.3$20.9 million has been spent to-date and $4.7$5.7 million is reported as an outstanding liability. At March 31,During the second quarter of 2006, the Companywe increased regulatory assets by $2.6 million for additional environmental cost estimates related to authorized sites, and at June 30, 2006, we had a total environmental regulatory asset of $19.1$21.7 million, which includes $14.4$16.0 million of total expenditures to date and accruals for additional estimated costs of $4.7$5.7 million. The Company believesWe believe the recovery of these costs is probable through the regulatory process after first pursuing recovery of costs from insurance. The CompanyWe also hashave an insurance receivable of $1.1 million, which is not included in the regulatory asset amount. The Company intendsWe intend to pursue recovery of these environmental costs from itsour general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. The Company considersWe consider insurance recovery probable based on a combination of factors, including a review of the terms of itsour insurance policies, the financial condition of the insurance companies providing coverage, a review of successful claims filed by other utilities with similar gas manufacturing facilities, and recent Oregon legislation that allows an insured party to seek recovery of “all sums” from one insurance company. The Company hasWe have notified the insurance companies but have not yet filed claims for insurance recovery nor have the insurance companies approved or denied coverage of these claims.
Legal Proceedings
The Company isWe are subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings, including the matters described below and in Part II, Item 8., Note 12, in the 2005 Form 10-K, cannot be predicted with certainty, the Company doeswe do not expect that the ultimate disposition of these matters will have a materially adverse effect on the Company’sour financial condition, results of operations or cash flows.
Industrial Customers Switching from Transportation to Sales Service.Georgia-Pacific Corporation vs. Northwest Natural Gas Company.In the fourth quarter of 2005, the Company settled a dispute with some large industrial customers related to gas costs charged to such customers upon electing to receive gas commodity under sales service instead of arranging for their own supplies through independent third parties. Two formal complaints filed with the OPUC in connection with this matter have been dismissed by the OPUC. The OPUC has also closed the investigation it opened to determine whether the Company had provided adequate information about rates to the industrial customers.
On Feb. 3, 2006, Georgia-Pacific Corporation filed suit against NW Natural (Georgia-Pacific(Georgia-Pacific Corporation v. Northwest Natural Gas Company, Case No. CV06-151-PK, United States District Court, District of
Oregon), alleging that NW Naturalwe offered to sell natural gas to Georgia-Pacific under the interruptible sales service provisions of the Company’s Rate Schedule 32 at a commodity rate set at the Company’sour Weighted Average Cost of Gas (WACOG). Georgia-Pacific further alleged that itwe accepted this offer and that the Companywe failed to perform as promised when, in October 2005, NW Naturalwe notified Georgia-Pacific that itwe would have to charge Georgia-Pacific the incremental costs of acquiring gas on the open market. Georgia-Pacific also allegesalleged breach of contract, promissory estoppel, fraudulent misrepresentation and breach of the duty of good faith and fair dealing. As
On Feb. 23, 2006, we filed a result, Georgia-Pacific is seeking damages inmotion for summary judgment on all claims. On June 30, 2006, an amount to be determined at trial but which they expect to be at least $235,000, plus consequential damages in an amount to be determined at trial. Georgia-Pacific further alleges thatorder was issued by failing to sell gas to Georgia-Pacific at the agreed upon price, NW Natural violated Oregon state laws that regulate utility operations, thereby entitling Georgia-Pacific to treble damages and attorney fees.
Prior to the Georgia-Pacific federal lawsuit being filed, on Jan. 5, 2006, NW Natural sought a declaratory judgment in the CircuitU.S. District Court for the StateDistrict of Oregon (NW Natural Gas Company v.dismissing the lawsuit with prejudice and denying all pending motions, if any, as moot. On July 27, 2006, Georgia-Pacific Corporation, Case No. 0601-00116, Multnomah County) declaring that, dueappealed this ruling to the rapid rise inNinth Circuit Court of Appeals. We do not expect the costoutcome of natural gas after hurricanes Katrina and Rita, the Company acted in accordance with its tariffs and all applicable laws when it informed Georgia-Pacific that it would not sell Georgia-Pacific natural gas at its WACOG price. When Georgia-Pacific responded by filing the federal lawsuit described above, and removing the declaratory judgment actionthis appeal to the federal courthave a material effect on Feb. 2, 2006, NW Natural voluntarily dismissed its suit for declaratory relief, and now all matters between the parties are before the federal court. NW Natural will vigorously contest the claimsour financial condition or results of Georgia-Pacific.operations.
Independent Backhoe Operator Action.Since May 2004 five lawsuits have been filed against the Company by 11 independent backhoe operators who performed backhoe services for the Company under contract. These five lawsuits have been consolidated into one consolidated case,Law and Zuehlke, et. al. v. Northwest Natural Gas Co.,CV-04-728-KI. The consolidated case consolidates the following cases previously reported:Kerry Law and Arnold Zuehlke, on behalf of themselves and all otherothers similarly situated v. Northwest Natural Gas Company (Filed(filed May 28, 2004 U.S. Dist. Ct. D. Or. Case No. CV-04-728-KI),Ike Whittlesey, C.G. Nick Courtney, Mark Parrish, John J. Shooter, Roger Whittlesey and Philip Courtney v. Northwest Natural (Filed(filed February 18, 2005 U.S. Dist. Ct. D. Or. Case No. CV-05-241-KI),Phillip Courtney v. Northwest Natural(Filedfiled April 12, 2005 U.S. Dist. Ct. D. Or., Case No. CV-05-507-BR), andKenneth Holtmann et. al. v. Northwest Natural(Filedfiled May 20, 2005 U.S. Dist. Ct. D. Or. Case No. 05-CV-00724-BR). The consolidated case also includes a fifth lawsuit filed on January 23, 2006,Larry L. Luethe v. Northwest Natural (U.S. Dist. Ct. D. Or. Case No. CV-06-098-MO).
Plaintiffs in the consolidated case are or have been independent backhoe operators who performed services for the Company under contract. Plaintiffs allege violation of the Fair Labor Standards Act for failure to pay overtime and also assert state wage and hour claims. Plaintiffs claim that they should have been considered “employees,” and seek overtime wages and interest in amounts to be determined, liquidated damages equal to the overtime award, civil penalties and attorneys’ fees and costs. Additionally, with the exception of the plaintiff inLarry L. Luethe v. Northwest Natural,plaintiffs allege that the failure to classify them as employees constituted a breach of contract and a tort under and with respect to certain unspecified employee benefits plans, programs and agreements. With the exception of the plaintiff inLarry L. Luethe v. Northwest Natural,plaintiffs seek an unspecified amount of damages for the value of what they would have received under these employee benefit plans if they had been classified as employees. The Company expectsWe expect that the plaintiff inLarry L. Luethe v. Northwest Naturalwill amend his complaint to include thesethis breach of contract and tort claims for unspecified damages.
In October 2005, the court granted the Company’s motion to stay plaintiffs’ claims pending exhaustion of the administrative review process with regard to each of the plans under which plaintiffs allege that they would have been eligible to receive benefits. The litigation is still stayed pending plaintiffs’ exhaustion of the administrative review process. There is insufficient information at this time to reasonably estimate the range of liability, if any, from these claims. NW NaturalWe will vigorously contest these claims and doesdo not expect the outcome of this litigation to have a material effect on itsour results of operations or financial condition.
Oregon Steel Mills site. In 2004, the Company waswe were served with a third-party complaint by the Port of Portland (Port) in a Multnomah County Circuit Court case,Oregon Steel Mills, Inc. v. The Port of Portland.Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by the Company’sNW Natural’s predecessor, Portland Gas & Coke Company, and ten other third-party defendants were
disposed of waste oil in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The Port’s complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. In March 2005, motions to dismiss by the CompanyNW Natural and other third-party defendants were denied on the basis that the failure of the Port to plead and prove that the Company waswe were in violation of law was an affirmative defense that may be asserted at trial, but did not provide a sufficient basis for dismissal of the Port’s claim. No date has been set for trial and discovery is ongoing. The Company doesWe do not expect that the ultimate disposition of this matter will have a materially adverse affecteffect on the Company’sour financial condition, results of operations or cash flows.
Comprehensive Income |
For the three and six months ended March 31,June 30, 2006 and 2005, reported net income was equivalent to total comprehensive income. Items that are excluded from net income and charged directly to common stock equity are accumulated in other comprehensive income (loss), net of tax. The amount of accumulated other comprehensive loss included in total common stock equity is $1.9 million at March 31,June 30, 2006, which is included in common stock equityrelated to our minimum pension liability (see “Consolidated Statements of Capitalization,” above).
11. | Subsequent Event |
On July 26, 2006, we granted a restricted stock award under our LTIP consisting of 6,500 shares, which will vest ratably on March 1, 2007, 2008 and 2009 (see Note 4).
PART I. FINANCIAL INFORMATION
Item 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Northwest Natural Gas Company (NW Natural) is a natural gas services company primarily engaged in the distribution of natural gas to residential, commercial and industrial customers, operating as a regulated utility business in Oregon and southwest Washington. NW Natural also is engaged in the delivery of interstate and intrastate gas storage services, operating as a non-utility business segment principally regulated by the Federal Energy Regulatory Commission (FERC). The utility is our largest business segment with approximately 98 percent of consolidated total assets. Factors critical to the success of the utility include maintaining a safe and reliable distribution system, acquiring and distributing natural gas supplies and services at a competitive price, and being able to recover the operating and capital costs in the rates charged to customers.
TheNW Natural also is engaged in the delivery of interstate and intrastate gas storage services, operating as a non-utility business segment principally regulated by the Federal Energy Regulatory Commission (FERC). This segment, which represents approximately 2 percent of consolidated total assets. This business segmentassets, provides services to large customers using storage and transportation capacity and asset optimization services provided under an agreement with an independent energy marketing company. Factors critical to the success of our interstate gas storagethis segment include being able to develop additional interstate storage capacity at competitive market prices and being able to continue asset optimization services using core utility assets under a regulatory sharing agreement.agreements.
In addition to the utility and interstate gas storage business segments, the consolidated financial statements include the accounts of a wholly-owned subsidiary business, NNG Financial Corporation (Financial Corporation), and other non-regulated activities, which together are referred to in this report as our Other business segment (see Note 2)7).
The following is management’s assessment of NW Natural’s financial condition including the principal factors that affect our results of operations. The discussion refers to our consolidated activities for the three and six months ended March 31,June 30, 2006 and 2005. ReferencesUnless otherwise indicated, references in this discussion to “Notes” are to the notes to the consolidated financial statements in this report. In addition to presenting results of operations and earnings amounts in total, certain measures are expressed in cents per share. These amounts reflect factors that directly impact earnings. We believe this per share information is useful because it enables readers to better understand the impact of these factors on earnings. All references to earnings per share in this report are on the basis of diluted shares, except where noted otherwise (see Part II, Item 8., Note 1, “Earnings Per Share,” in the 2005 Form 10-K).
Issues and Challenges
There are a number of factors that directly affect our consolidated financial condition and results of operations. The most significant factor we face in the near term is the impact of higher gas prices. While wholesale gas prices havehad declined in recent months, the current forward market price for natural gas remains higher than the levels we currently have embedded in our utility customers’ rates, which means our customers’ rates are likely to increase this fall. The majority of our gas supply market tightened last year when hurricanes hit parts ofsupplies come from Alberta and British Columbia, while the United States, and they remain tight early this year.remainder comes from the U.S. Rocky Mountain region. We believe we have sufficient supplies of natural gas under contract to meet the needs of our firm customers, but further price increases could change our competitive advantage and our customers’ preference for natural gas. If higher gas prices persist, it could affect our ability to add residential and commercial customers and could result in industrial customers shifting their businesses’ energy needs to alternative fuel sources.
Other issues and challenges we could face in the future include unpredictable weather conditions, adverse regulatory actions or policy changes, managing gas supplies, storage and transportation capacity, managing customer growth, maintaining a competitive advantage, managing
environmental risks, and managing interest rate and credit risks. For a more complete discussion of these and other risks, see Part II, Item 7., “Issues, Challenges and Performance Measures,” and Part I, Item 1A., “Risk Factors,” in the 2005 Form 10-K.
To address some of the challenges, we recently initiated a company-wide restructuring of operations with the goal of significantly improving work processes, reducing operating expenses and capital costs, and continuing to strive for excellence in customer service. Our focus has been on developing initiatives to achieve long-term strategic targets. Implementation of these initiatives will involve:
This improved operations model is expected to be implemented over the next several years and to include workforce reductions. These reductions are expected to be accomplished by primarily focusing on a combination of normal attrition and voluntary severance packages. Accordingly, we expect to incur costs of about $1.5 million to $2.0 million in the fourth quarter of 2006 related to a workforce reduction of an estimated 50-100 people, which we expect to largely offset by a combination of cost reductions and gains from non-core asset sales.
Application of Critical Accounting Policies and Estimates
In preparing our financial statements using generally accepted accounting principles in the United States of America (GAAP), management exercises judgment in the selection and application of accounting principles, including making estimates and assumptions that affect reported amounts of assets, liabilities, revenues, expenses and related disclosures in the financial statements. Management considers our critical accounting policies to be those which are most important to the representation of our financial condition and results of operations and which require management’s most difficult and subjective or complex judgments, including accounting estimates that could result in materially different amounts if we reported under different conditions or using different assumptions.
Our most critical estimates or judgments involve regulatory cost recovery, unbilled revenues, derivative instruments, pension assumptions, income taxes and environmental and other contingencies (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates,” in the 2005 Form 10-K). There have been no material changes to the information provided in our 2005 Form 10-K with respect to the application of critical accounting policies and estimates. Management has discussed its estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board.
Within the context of our critical accounting policies and estimates, management is not currently aware of any reasonably likely events or circumstances that would result in materially different amounts being reported.
Earnings and Dividends
Three months ended June 30, 2006 compared to June 30, 2005:
Net income was $41.0$2.0 million, or $1.487 cents a share, for the three months ended March 31, 2006, as compared to $39.9$1.1 million, or $1.434 cents a share, forin the same period last year.in 2005. The increase in net income was attributableprimarily due to improved results from our regulated utility and interstate gas storage segments. InNW Natural’s utility operations contributed $0.2 million, or 1 cent a share, to earnings in the firstsecond quarter of 2006, we earned $39.5 million, or $1.43 a share,compared to negligible earnings in 2005. Net income from utility operations representing an increaseis typically low during the second quarter due to the reduced use of $0.7natural gas in the spring and early summer. Interstate gas storage operations contributed $1.8 million to earnings in the second quarter of 2006, or 6 cents a share, compared to $0.8 million, or 3 cents a share, overin the prior year; and we earned $1.4same period in 2005. Other non-utility activities resulted in a negligible loss for the quarter compared to a gain of $0.3 million, or 5 cents1 cent a share, from interstate gas storage operations representing an increase of $0.5 million, or 2 cents a share, over the prior year.
First quarter of 2006 compared to first quarter of 2005:in 2005.
Primary factors affecting firstsecond quarter earnings this year over last year include:
a positivean increase in utility margin contribution of $1.8$1.7 million this year, representing a sharing of utilityfrom gas costpurchase savings under the regulatory Purchased Gas Adjustment (PGA) incentive mechanism, was equivalent to last
|
Six months ended June 30, 2006 compared to June 30, 2005:
For the six months ended June 30, 2006, net income increased 5 percent to $43.0 million, or $1.56 a share, compared to $41.0 million, or $1.48 a share, in the same period in 2005. NW Natural’s utility operations contributed $39.7 million, or $1.44 a share, to earnings in the first six months of 2006, compared to $38.9 million, or $1.40 a share, in 2005. Interstate gas storage operations contributed $3.3 million in the current period, or 12 cents a share, compared to $1.7 million, or 6 cents a share, in 2005. Other non-utility activities resulted in net income of $0.1 million, or less than 1 cent a share, compared to net income of $0.4 million, or 2 cents a share, in 2005.
Primary factors affecting year-to-date earnings this year over last year include:
a decrease in utility margin from industrial customers of $0.3 million, or 2 percent, primarily due to a $0.3 million net loss from a temporary mark-to-market contract adjustment
and a higher percentage of volumes in lower margin rate schedules, partially offset by higher delivered volumes; |
Dividends paid on common stock were 34.5 cents and 32.5 cents a share in the three-month periods ended March 31,June 30, 2006 and 2005, respectively, and 69 cents and 65 cents a share in the six-month periods ended June 30, 2006 and 2005, respectively. In AprilJuly 2006, the Company’s Board of Directors declared a dividend of 34.5 cents a share on the common stock, payable MayAug. 15, 2006, to shareholders of record on April 28,July 31, 2006. The current indicated annual dividend rate is $1.38 a share.
Results of Operations
Regulatory Developments
We provide gas utility service in Oregon and Washington, with Oregon representing over 90 percent of our utility revenues. Future earnings and cash flows from utility operations will be determined by, among other factors, our ability to obtain reasonable and timely regulatory treatment for operating expenses and investments in utility plant. See Part II, Item 7., “Results of Operations– Regulatory Matters,” in the 2005 Form 10-K.
General Rate Cases
On June 30, 2006, the two companies that provide interstate pipeline transportation of our gas supplies filed general rate cases. Williams Gas Pipeline—West, or Northwest Pipeline, filed for a 49 percent rate increase, which would increase our rates by approximately $17.4 million annually. The primary drivers for Northwest Pipeline’s proposed increase are pipeline integrity expenses, mainline and other extension construction, capacity replacement and displacement of supply from the Rocky Mountain region. Gas Transmission Northwest, or GTN, filed for a rate increase of 71 percent, which would increase our rates by approximately $3.1 million. The primary drivers for GTN’s rate increase are return on equity, capital structure, capacity releases and pipeline integrity expenses. Rates for both Northwest Pipeline and GTN are expected to be effective January 1, 2007, subject to credit to customers. Increases in pipeline transportation expenses are subject to our PGA mechanism and are 100 percent passed-through to customers in both Oregon and Washington. See “Rate Mechanisms,” below.
Rate Mechanisms
Purchased Gas Adjustment.Rate changes are applied each year under the PGA mechanisms in our tariffs in Oregon and Washington to reflect changes in the costs of natural gas commodity purchased under contracts with gas producers, the application of temporary rate adjustments to amortize balances in deferred regulatory asset and liability accounts and the removal of temporary rate adjustments effective for the previous year.
Under the current PGA mechanisms, we collect an amount for purchased gas costs based on estimates included in rates. If the actual purchased gas costs are higher than the amounts included in rates, we are not allowedrequired to charge customers immediately fordefer a predetermined percentage of the higher costs but defer the costs and collect them in the future.future rates. Similarly, when the actual purchased gas costs are lower than the amounts included in rates, the gas
cost savings are not immediately returned to customers, but area predetermined percentage is deferred and refundedcredited to customers in future periods. As part of an incentive mechanism in Oregon, wethe impact on current earnings is either a charge to expense for 33 percent of the higher cost of gas sold, or a credit to expense for 33 percent of the lower cost to earnings.of gas sold. In Washington, the PGA deferral is currently based on pass-through of 100 percent of the higher or lower actual cost of gas sold.
Regulatory and Insurance Recovery for Environmental Matters.In May 2003, the OPUC approved NW Natural’s request for deferral of environmental costs associated with specific sites, including the Gasco, Siltronic and Portland Harbor sites. The authorization, which has been extended through January 2007 and expanded to include the Oregon Steel Mills site, allows NW Natural to defer and seek recovery of unreimbursed environmental costs in a future general rate case. In April 2006, the OPUC authorized NW Natural to accrue interest on deferred balances effective Jan. 27, 2006, subject to an annual demonstration to the OPUC that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. As of March 31, 2006, we have paid a cumulative total of $14.4 million relating to the named sites since the effective date of the deferral authorization.
On a cumulative basis, NW Natural has recognized a total of $24.0 million for environmental costs, including legal, investigation, monitoring and remediation costs. Of this total, $19.3 million has been spent to-date and $4.7 million is reported as an outstanding liability. At March 31, 2006, we had a regulatory asset of $19.1 million which includes $14.4 million of total expenditures to date and accruals for additional estimated costs of $4.7 million. We believe the recovery of these costs is probable through the regulatory process after first pursuing recovery of costs from insurance. We also have an insurance receivable of $1.1 million, which is not included in the regulatory asset amount. We intend to pursue recovery of these environmental costs from our general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. We consider insurance recovery probable based on a combination of factors, including a review of the terms of our insurance policies, the financial condition of the insurance companies providing coverage, a review of successful claims filed by other utilities with similar gas manufacturing facilities, and recent Oregon legislation that allows an insured party to seek recovery of “all sums” from one insurance company. We have not filed claims for insurance recovery nor have the insurance companies approved or denied coverage of these claims.
Geo-hazard Program. We entered into a stipulation with the OPUC in 2001 for an enhanced pipeline safety program that included an accelerated bare steel replacement program and a geo-hazard safety program. The geo-hazard safety program included the identification, assessment and remediation of risks to piping infrastructure created by landslides, washouts, earthquakes or similar occurrences. The stipulation allowed NW Natural to receive deferred accounting rate treatment commencing Oct. 1, 2002, for all costs associated with the programs exceeding $3 million per year.geo-hazard program. The authority to defer expenses for costs associated with the geo-hazard program expiresis scheduled to expire on Dec. 31, 2006.
Utility Regulation Legislation
During 2005, the Oregon legislature passed and Oregon’s Governor signed into law Senate Bill (SB) 408 effective forrelating to taxes collected by utilities on or after Jan. 1, 2006. This legislation requires the OPUC to establish an annual tax adjustment to ensure that Oregon utilities do not collect in rates more income taxes than they actually pay to government entities. See Part I, Item 1., “Regulation and Rates—Utility Regulation Legislation,” Part IA.1A., “Risk Factors,” and Part II, Item 7., “Results of Operations—Regulatory Matters—Utility Regulation Legislation,” in the 2005 Form 10-K. The OPUC continues to develop rules required to implement SB 408 and draftwith a proposed set of final rules are expected to be fileddistributed by the OPUC staff inon July 25, 2006, with finaland adoption of final rules scheduled for September 2006. Due to take place in September. We continue to participate in the rulemaking development process, along with members of the OPUC’s staff, interveners and other affected utilities. However, due to the many uncertainties related to the OPUC’s interpretations and rule making with respect to the applicationimplementation of the bill’s provisions,OPUC’s proposed final rules, we are not able to determine at this time what impact, if any, the new legislation will have on our financial condition, results of operations or cash flows, but the impact may be material.
Comparison of Gas Distribution Operations
The following table summarizestables summarize the composition of utility volumes, operating revenues and margin for the three months ended March 31:margin:
Thousands, except degree day and customer data | 2006 | 2005 | |||||||||||
Utility volumes - therms: | |||||||||||||
Residential and commercial sales | 253,899 | 62 | % | 230,683 | 62 | % | |||||||
Industrial sales and transportation | 154,037 | 38 | % | 138,487 | 38 | % | |||||||
Total utility volumes sold and delivered | 407,936 | 100 | % | 369,170 | 100 | % | |||||||
Utility operating revenues - dollars: | |||||||||||||
Residential and commercial sales | $ | 326,785 | 84 | % | $ | 258,542 | 84 | % | |||||
Industrial sales and transportation | 61,911 | 16 | % | 42,991 | 14 | % | |||||||
Other revenues | (1,440 | ) | — | % | 5,153 | 2 | % | ||||||
Total utility operating revenues | $ | 387,256 | 100 | % | $ | 306,686 | 100 | % | |||||
Cost of gas sold | 255,384 | 180,567 | |||||||||||
Revenue taxes | 9,528 | 7,183 | |||||||||||
Utility net operating revenues (margin) | $ | 122,344 | $ | 118,936 | |||||||||
Utility margin:(1) | |||||||||||||
Residential sales | $ | 78,348 | 64 | % | $ | 70,055 | 59 | % | |||||
Commercial sales | 31,777 | 26 | % | 27,675 | 23 | % | |||||||
Industrial - firm sales and transportation | 3,608 | 3 | % | 3,741 | 3 | % | |||||||
Industrial - interruptible sales and transportation | 4,878 | 4 | % | 5,058 | 4 | % | |||||||
Miscellaneous revenues | 1,503 | 1 | % | 1,898 | 2 | % | |||||||
Other margin adjustments | 1,440 | 1 | % | 2,465 | 2 | % | |||||||
Margin before regulatory mechanism adjustments | 121,554 | 99 | % | 110,892 | 93 | % | |||||||
Weather normalization mechanism | 1,842 | 2 | % | 3,246 | 3 | % | |||||||
Decoupling mechanism | (1,052 | ) | (1 | %) | 4,798 | 4 | % | ||||||
Utility margin | $ | 122,344 | 100 | % | $ | 118,936 | 100 | % | |||||
Total number of customers (end of period) | 624,297 | 603,330 | |||||||||||
Actual degree days | 1,814 | 1,769 | |||||||||||
Percent colder (warmer) than average | (3%) | (5%) | |||||||||||
Three Months Ended June 30, | ||||||||||||||
Thousands, except degree day and customer data | 2006 | 2005 | ||||||||||||
Utility volumes - therms: | ||||||||||||||
Residential and commercial sales | 95,097 | 41 | % | 99,193 | 41 | % | ||||||||
Industrial sales and transportation | 134,481 | 59 | % | 140,547 | 59 | % | ||||||||
Total utility volumes sold and delivered | 229,578 | 100 | % | 239,740 | 100 | % | ||||||||
Utility operating revenues - dollars: | ||||||||||||||
Residential and commercial sales | $ | 127,762 | 76 | % | $ | 113,807 | 75 | % | ||||||
Industrial sales and transportation | 38,086 | 23 | % | 37,267 | 25 | % | ||||||||
Other revenues | 1,402 | 1 | % | 573 | 0 | % | ||||||||
Total utility operating revenues | 167,250 | 100 | % | 151,647 | 100 | % | ||||||||
Cost of gas sold | 105,007 | 92,378 | ||||||||||||
Revenue taxes | 4,196 | 3,593 | ||||||||||||
Utility net operating revenues (margin) | $ | 58,047 | $ | 55,676 | ||||||||||
Utility Margin:(1) | ||||||||||||||
Residential sales | $ | 33,556 | 58 | % | $ | 34,357 | 62 | % | ||||||
Commercial sales | 13,699 | 24 | % | 14,517 | 26 | % | ||||||||
Industrial - firm sales and transportation | 2,864 | 5 | % | 3,057 | 6 | % | ||||||||
Industrial - interruptible sales and transportation | 4,840 | 8 | % | 4,671 | 8 | % | ||||||||
Miscellaneous revenues | 1,145 | 2 | % | 1,331 | 2 | % | ||||||||
Other margin adjustments | 1,982 | 3 | % | 405 | 1 | % | ||||||||
Margin before weather normalization and decoupling | 58,086 | 100 | % | 58,338 | 105 | % | ||||||||
Weather normalization mechanism | 844 | 1 | % | (691 | ) | -1 | % | |||||||
Decoupling mechanism | (883 | ) | -1 | % | (1,971 | ) | -4 | % | ||||||
Utility margin | $ | 58,047 | 100 | % | $ | 55,676 | 100 | % | ||||||
Customers - end of period: | ||||||||||||||
Residential customers | 563,750 | 544,595 | ||||||||||||
Commercial customers | 59,853 | 59,027 | ||||||||||||
Industrial customers | 942 | 950 | ||||||||||||
Total number of customers - end of period | 624,545 | 604,572 | ||||||||||||
Actual degree days | 572 | 652 | ||||||||||||
Percent colder (warmer) than average(2) | (16 | %) | (5 | %) | ||||||||||
(25-year average degree days is used as average) |
Thousands, except degree day data Utility volumes - therms: Residential and commercial sales Industrial sales and transportation Total utility volumes sold and delivered Utility operating revenues - dollars: Residential and commercial sales Industrial sales and transportation Other revenues Total utility operating revenues Cost of gas sold Revenue taxes Utility net operating revenues (margin) Utility Margin:(1) Residential sales Commercial sales Industrial - firm sales and transportation Industrial - interruptible sales and transportation Miscellaneous revenues Other margin adjustments Margin before weather normalization and decoupling Weather normalization mechanism Decoupling mechanism Utility margin Actual degree days Percent colder (warmer) than average(2) (25-year average degree days is used as average) Six Months Ended June 30, 2006 2005 349,734 55 % 330,405 54 % 287,780 45 % 278,505 46 % 637,514 100 % 608,910 100 % $ 454,913 82 % $ 372,801 81 % 99,631 18 % 79,806 17 % (38 ) 0 % 5,726 1 % 554,506 100 % 458,333 100 % 360,391 272,945 13,724 10,776 $ 180,391 $ 174,612 $ 111,904 62 % $ 104,412 60 % 45,476 25 % 42,192 24 % 6,472 4 % 6,798 4 % 9,718 5 % 9,729 5 % 2,648 2 % 3,229 2 % 3,422 2 % 2,870 2 % 179,640 100 % 169,230 97 % 2,686 1 % 2,555 1 % (1,935 ) -1 % 2,827 2 % $ 180,391 100 % $ 174,612 100 % 2,386 2,421 (6 %) (5 %)
(1) | Amounts reported as margin for each category |
(2) | Average weather represents the 25-year average degree days as determined in our last general rate case. |
Our utility results are affected by, among other things, by customer growth and by changes in weather and customer consumption patterns, with a significant portion of our earnings being derived from natural gas sales to residential and commercial customers. In order to offset the potential volatility in utility earnings caused by these factors, we obtained OPUC approval of a conservation tariff that
adjusts margin up or down based on changes in residential and commercial customer consumption and a weather normalization mechanism that adjusts customer bills, and our margin, based on above- or below-average temperatures during the winter heating season (see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms,” in the 2005 Form 10-K).
Three months and six months ended June 30, 2006 compared to June 30, 2005:
Total utility volumes sold and delivered in the second quarter this year over last year decreased 4 percent, while total utility margin increased by 4 percent. Total utility volumes sold and delivered in the first quarterhalf of 2006this year over last year increased 115 percent compareddue mainly to the first quarter of 2005. In the three months ended March 31, 2006, weather was 3 percent colder than the comparable period in 2005, but 3 percent warmer than average.
Customercustomer growth, which has continued to remain strong, with a net increase of 20,96719,973 customers since March 31,June 30, 2005 or an annual growth rate of 3.5 percent. In the three years ended Dec. 31, 2005, more than 57,000 customers were added, representing an average annual growth rate of 3.3 percent.
Residential and Commercial Sales
Results of operations in the residentialResidential and commercial sales markets are largely impacted by seasonal weather patterns, energy prices, competition from alternative energy sources and economic conditions in our service areas. The following table summarizes the utility volumes and utility operating revenues in the residential and commercial markets for the three months ended March 31:
Thousands, except customers | 2006 | 2005 | ||||||
Utility volumes - therms: | ||||||||
Residential sales | 176,111 | 158,931 | ||||||
Commercial sales | 103,316 | 93,349 | ||||||
Change in unbilled sales | (25,528 | ) | (21,597 | ) | ||||
Total weather-sensitive utility volumes | 253,899 | 230,683 | ||||||
Utility operating revenues - dollars: | ||||||||
Residential sales | $ | 238,383 | $ | 189,252 | ||||
Commercial sales | 121,700 | 94,422 | ||||||
Change in unbilled sales | (33,298 | ) | (25,132 | ) | ||||
Total weather-sensitive utility revenues | $ | 326,785 | $ | 258,542 | ||||
Total number of customers (end of period) | 623,353 | 602,388 | ||||||
First quarter of 2006 compared to first quarter of 2005:
The primary factors affecting residential and commercial volumes and operating revenues in the first quarter this year over last year include:
Typically, 80 percent or more of annual utility operating revenues are derived from gas sales to weather-sensitive residential and commercial customers. Although variations in temperatures between periods will affect volumes of gas sold to these customers, the effect on margin and net income
is significantly reduced due to the weather normalization mechanism in Oregon. ThisHowever, this mechanism applies to approximately 92 percent of our Oregon customers. In Washington, our customers, arebut we do not covered byhave a weather normalization mechanism in Washington, where approximatelyabout 10 percent of our customers are served. SoAs a result, the mechanism does not fully insulate us from utility earnings from volatility due to weather. We also utilize a decoupling mechanism that is intended to break the link between our earnings and the quantity of gas consumed by our customers, so that we do not have an incentive to discourage customers from conserving energy.
The weather normalization mechanism contributedrecovered a net $1.8$0.8 million of margin in the second quarter of 2006 on weather that was 316 percent warmer than normalaverage. This compares to a reduction of $0.7 million to margin in the three monthsame period ended March 31, 2006, compared to $3.2 millionlast year based on weather that was 5 percent warmer than normalaverage. The decoupling mechanism reduced margin by $0.9 million in the second quarter of 2006, compared to a reduction of $2.0 million in the same period last year.
During the six-month period in 2006, the weather normalization mechanism recovered a net $2.7 million of margin based on 6 percent warmer than average weather, compared to a margin recovery of $2.5 million in the same 2005 period based on 5 percent warmer than average weather. The decoupling mechanism reduced margin by $1.9 million in the first threesix months of 2006, compared to a contribution of $2.8 million in the same period last year.
The following table summarizes the utility volumes and utility operating revenues in the residential and commercial markets:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Thousands | 2006 | 2005 | 2006 | 2005 | ||||||||||||
Utility volumes - therms: | ||||||||||||||||
Residential sales | 72,047 | 71,569 | 248,158 | 230,500 | ||||||||||||
Commercial sales | 48,295 | 47,508 | 151,611 | 140,857 | ||||||||||||
Change in unbilled sales | (25,245 | ) | (19,884 | ) | (50,035 | ) | (40,952 | ) | ||||||||
Total weather-sensitive utility volumes | 95,097 | 99,193 | 349,734 | 330,405 | ||||||||||||
Utility operating revenues - dollars: | ||||||||||||||||
Residential sales | $ | 100,808 | $ | 86,888 | $ | 339,191 | $ | 276,139 | ||||||||
Commercial sales | 56,863 | 47,803 | 178,563 | 142,226 | ||||||||||||
Change in unbilled sales | (29,909 | ) | (20,884 | ) | (62,841 | ) | (45,564 | ) | ||||||||
Total weather-sensitive utility revenues | $ | 127,762 | $ | 113,807 | $ | 454,913 | $ | 372,801 | ||||||||
Three months ended June 30, 2006 compared to June 30, 2005:
The primary factors affecting residential and commercial volumes and operating revenues in the second quarter this year over last year include:
Six months ended June 30, 2006 compared to June 30, 2005:
The primary factors affecting residential and commercial volumes and operating revenues year-to-date this year over last year include:
Total utility operating revenues include accruals for unbilled revenues (gas delivered but not yet billed to customers) based on estimates of gas deliveries from that month’s meter reading dates to month end. Amounts reported as unbilled revenues reflect the increase or decrease in the balance of accrued unbilled revenues compared to the prior year-end.period end. Weather conditions, rate changes and customer billing dates affect the balance of accrued unbilled revenues at the end of each month. At March 31,June 30, 2006, accrued unbilled revenue was $47.8$16.7 million compared to $38.9$17.2 million at March 31,June 30, 2005.
Industrial Sales and Transportation
The following table summarizes the delivered volumes and utility operating revenues in the industrial market for the threemarket:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Thousands | 2006 | 2005 | 2006 | 2005 | ||||||||||||
Utility volumes - therms: | ||||||||||||||||
Industrial - firm sales | 15,924 | 16,823 | 40,075 | 38,561 | ||||||||||||
Industrial - firm transportation | 35,348 | 37,215 | 65,091 | 66,312 | ||||||||||||
Industrial - interruptible sales | 25,256 | 35,130 | 68,444 | 71,448 | ||||||||||||
Industrial - interruptible transportation | 58,358 | 51,827 | 115,313 | 103,161 | ||||||||||||
Change in unbilled sales | (405 | ) | (448 | ) | (1,143 | ) | (977 | ) | ||||||||
Total utility volumes | 134,481 | 140,547 | 287,780 | 278,505 | ||||||||||||
Utility operating revenues - dollars: | ||||||||||||||||
Industrial - firm sales | $ | 15,404 | $ | 13,503 | $ | 39,156 | $ | 31,047 | ||||||||
Industrial - firm transportation | 1,169 | 1,027 | 2,117 | 2,114 | ||||||||||||
Industrial - interruptible sales | 20,384 | 21,376 | 55,736 | 43,989 | ||||||||||||
Industrial - interruptible transportation | 1,868 | 1,745 | 3,727 | 3,492 | ||||||||||||
Change in unbilled sales | (739 | ) | (384 | ) | (1,105 | ) | (836 | ) | ||||||||
Total utility operating revenues | $ | 38,086 | $ | 37,267 | $ | 99,631 | $ | 79,806 | ||||||||
Three months ended March 31:June 30, 2006 compared to June 30, 2005:
Total volumes delivered to industrial sales and transportation customers were down 6.1 million therms, or 4 percent, in the second quarter of 2006 as compared to the same period in 2005. Utility operating revenues were up $0.8 million, or 2 percent, over last year. The higher revenues reflect higher billing rates due to increased gas costs. However, the margin contribution from industrial sales and transportation was flat compared to 2005, primarily driven by a $0.4 million gain recognized from a temporary mark-to-market contract adjustment, offset by a decrease in volumes and a higher percentage of volumes in lower margin rate schedules.
Thousands, except customers | 2006 | 2005 | ||||
Utility volumes - therms: | ||||||
Industrial - firm sales | 24,151 | 21,738 | ||||
Industrial - firm transportation | 29,743 | 29,097 | ||||
Industrial - interruptible sales | 43,188 | 36,318 | ||||
Industrial - interruptible transportation | 56,955 | 51,334 | ||||
Total utility volumes | 154,037 | 138,487 | ||||
Utility operating revenues - dollars: | ||||||
Industrial - firm sales | $ | 23,752 | $ | 17,544 | ||
Industrial - firm transportation | 948 | 1,087 | ||||
Industrial - interruptible sales | 35,352 | 22,613 | ||||
Industrial - interruptible transportation | 1,859 | 1,747 | ||||
Total utility operating revenues | $ | 61,911 | $ | 42,991 | ||
Total number of customers (end of period) | 944 | 942 | ||||
Six months ended June 30, 2006 compared to June 30, 2005:
Total volumes delivered to industrial sales and transportation customers were up 15.69.3 million therms, or 113 percent, in the first quarter ofsix months ended June 30, 2006, as compared to the same period in 2005, and utility2005. Utility operating revenues were up $18.9$19.8 million, or 4425 percent, over last year. The higher revenues primarily reflect a shift of customers from transportation to sales service and higher billing rates due to increased gas costs.costs, plus higher volumes delivered. The margin contribution from industrial sales and transportation customers decreased by $0.3 million, or 42 percent, over 2005, due to a $0.3 million temporary net loss mark-to-market lossadjustment related to a temporarythe valuation of a gas sale contract.sales contract and a higher percentage of volumes in lower margin rate schedules, partially offset by higher delivered volumes.
Other Revenues
Other revenues include miscellaneous fee income as well as utility revenue adjustments reflecting deferrals to, or amortizations from, regulatory asset or liability accounts other than deferrals relating to gas costs (see Part II, Item 8., Note 1, “Industry Regulation”,Regulation,” in the 2005 Form 10-K). Other
revenues decreasedincreased net operating revenues by $1.4 million in the firstsecond quarter of 2006, compared to an increase of $5.2$0.6 million in the second quarter of 2005. In the first half of 2006, other revenues were negligible, compared to an increase of $5.7 million in the first quarterhalf of 2005. The following table summarizes other revenues by primary category for the threemajor category:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Thousands | 2006 | 2005 | 2006 | 2005 | ||||||||||||
Current regulatory deferrals: | ||||||||||||||||
Decoupling mechanism | $ | (883 | ) | $ | (1,971 | ) | $ | (1,935 | ) | $ | 2,827 | |||||
Weather normalization mechanism | (1,335 | ) | (505 | ) | 234 | (33 | ) | |||||||||
South Mist pipeline extension | — | 212 | — | 293 | ||||||||||||
Coos Bay distribution system | — | 98 | — | 703 | ||||||||||||
Current regulatory amortizations: | ||||||||||||||||
Interstate gas storage credits | 4,051 | 2,714 | 4,051 | 2,714 | ||||||||||||
Decoupling mechanism | (1,141 | ) | (397 | ) | (3,829 | ) | (1,236 | ) | ||||||||
South Mist pipeline extension | (15 | ) | (499 | ) | (51 | ) | (1,568 | ) | ||||||||
Coos Bay distribution system | (213 | ) | — | (693 | ) | — | ||||||||||
Conservation programs | (304 | ) | (441 | ) | (978 | ) | (1,329 | ) | ||||||||
Other | 97 | 75 | 324 | 235 | ||||||||||||
Net revenue adjustments | 257 | (714 | ) | (2,877 | ) | 2,606 | ||||||||||
Customer fees | 1,076 | 1,251 | 2,721 | 3,021 | ||||||||||||
Other | 69 | 36 | 118 | 99 | ||||||||||||
Total miscellaneous revenues | 1,145 | 1,287 | 2,839 | 3,120 | ||||||||||||
Total other revenues | $ | 1,402 | $ | 573 | $ | (38 | ) | $ | 5,726 | |||||||
Three months ended March 31:June 30, 2006 compared to June 30, 2005:
Thousands | 2006 | 2005 | ||||||
Revenue adjustments: | ||||||||
Current regulatory deferrals: | ||||||||
Decoupling mechanism | $ | (1,052 | ) | $ | 4,798 | |||
Weather normalization mechanism | 1,569 | 472 | ||||||
South Mist pipeline extension | — | 81 | ||||||
Coos Bay distribution system | — | 605 | ||||||
Current regulatory amortizations: | ||||||||
Decoupling mechanism | (2,688 | ) | (839 | ) | ||||
South Mist pipeline extension | (36 | ) | (1,069 | ) | ||||
Coos Bay distribution system | (480 | ) | — | |||||
Conservation programs | (674 | ) | (888 | ) | ||||
Year 2000 technology costs | 230 | (496 | ) | |||||
Other | (3 | ) | 656 | |||||
Net revenue adjustments | (3,134 | ) | 3,320 | |||||
Miscellaneous revenues: | ||||||||
Customer fees | 1,645 | 1,770 | ||||||
Other | 49 | 63 | ||||||
Total miscellaneous revenues | 1,694 | 1,833 | ||||||
Total other revenues | $ | (1,440 | ) | $ | 5,153 | |||
Other revenues in the three months ended March 31,June 30, 2006 were $6.6$0.8 million lowerhigher than in the three months ended March 31,June 30, 2005 primarily due to a decreasean increase in deferrals under the decoupling mechanisminterstate gas storage credits ($5.91.3 million) and, partially offset by an increase in the amortization of the decoupling deferral balances ($1.80.7 million).
Six months ended June 30, 2006 compared to June 30, 2005:
Other revenues in the six months ended June 30, 2006 were $5.7 million lower than in the six months ended June 30, 2005 primarily due to a decrease in decoupling deferrals ($4.8 million) and an increase in amortization of decoupling deferral balance ($2.6 million), partially offset by an increase in the weather normalizationinterstate gas storage credits ($1.3 million). For further discussion of regulatory revenue adjustments, ($1.1 million). Seesee Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms,” in the 2005 Form 10-K.
Cost of Gas Sold
NaturalAlthough natural gas commodity prices have increased significantly in recent periods, withthe last few years, prices had moderated recently, allowing more opportunity to purchase lower-priced spot market gas. During the second quarter and the first six months of 2006, the cost per therm of gas sold was 27 percent and 16 percent higher, respectively, than in the first quarter of 2006 than the first quarter of 2005.comparable 2005 periods, reflecting higher natural gas prices and our fixed-price commodity price hedge contracts. The cost per therm of gas sold includes
current gas purchases, gas withdrawn from storage inventory, gains and losses from financial commodity price hedge contracts,hedges, margin from off-system gas sales, demand cost balancing adjustments, regulatory deferrals and company use (see Part II, Item 7., “Results of Operations—Comparison of Gas Distribution Operations—Cost of Gas Sold,” in the 2005 Form 10-K).use.
We utilizeuse a natural gas commodity-price hedge program under the terms of our Derivatives Policy to help manage our floatingvariable price risk on gas commodity contracts (see “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” above, and Note 4).purchases. We realized a net loss from financial hedge gainscontracts of $17.5$10.5 million from this program duringin the first quarter ofthree months ended June 30, 2006 compared to a gain of $11.3 million during the same period in 2005. During the six months ended June 30, 2006, we realized a net losseshedge gain of $1.5$7.0 million incompared a gain of $9.8 million during the first three months ofsame period in 2005. Gains and losses relating to the financial hedging of utility gas pricespurchases are included in cost of gas, which isgas. Realized losses were factored into our PGA deferrals and annual rate changes,changes. As such, these gains and thereforelosses have no material impact on net income.
Under our PGA tariff in Oregon, if the cost of gas purchased is higher or lower than the cost embedded in rates, net income from Oregon operations is affected within defined limits by changescharged or credited for 33 percent of the difference and the remaining 67 percent is deferred for pass through to customers in purchasedfuture rates. Our gas costs (see Part II, Item 7., “Results of Operations—Comparison of Gas Operations—Cost of Gas Sold,”purchases in the 2005 Form 10-K). Our purchased gas costs in the first quarterssecond quarter of both 2006 and 2005 were lower than the costs embedded in rates, which, underand our share of the PGA sharing mechanism,lower costs increased margin by $1.8 million. For the second quarter of 2005, our gas costs were also lower than the gas costs embedded in rates, and our share of the lower costs increased margin by $0.2 million. In the first six months of 2006, our share of gas cost savings contributed $3.6 million to margin, compared to net savings and a contribution to margin of $2.0 million in the comparable 2005 period. The benefit to customers of gas cost savings amounted to $3.7 million and $1.5 million, respectively.
We are also able to use surplus gas supplies under contract but not required for delivery to core market (residential, commercial and industrial firm) customers, due to warmer weather and other factors, to make off-system sales. Under the PGA tariff in Oregon, we retain 33 percent of the margins realized from our off-system gas sales and defer the remaining 67 percent to a regulatory asset or liability account for recovery from, or refund to, customers in future rates. Our share of margin from off-system gas sales in the first quarter of 2006 was a negligible gain compared to a gain of $0.4$7.4 million for the three and six months ended June 30, 2006, respectively.
Based on current forward curve prices, we began moderating our hedging positions compared to prior years, but at the same periodtime we have increased our gas inventory injections into storage while spot prices were lower. Typically, we have a higher percentage of the next gas year’s estimated purchase requirements hedged at this time of year. We may or may not increase our hedging positions to be closer to the level of the past few years, depending on movement in 2005.forward market prices and our assessment of risk. Having a greater percentage of unhedged gas purchases may subject NW Natural to greater purchased gas cost variability in the future as compared to previous years. See Part II, Item 1A., “Risk Factors,” below. Variations in gas costs are subject to our PGA mechanism. See “Results of Operations—Rate Mechanisms,” above.
Business Segments Other than Gas Distribution Operations
Interstate Gas Storage
We earned netNet income from our non-utility interstate gas storage business segment in the three and six months ended March 31,June 30, 2006 of $1.4was $1.8 million and $3.3 million, respectively, after regulatory sharing and income taxes, or 56 cents and 12 cents a share.share, respectively. This compares to net income of $0.9$0.8 million, or 3 cents a share, and $1.7 million, or 6 cents a share, in the three and six months ended March 31, 2005.June 30, 2005, respectively. The increase was primarily due to additional interstate storage capacity brought on line during 2006, plusmid-year 2005 and an increase in revenues from our asset optimization program with an unaffiliated energy marketing company (see Part II, Item 7., “Results of Operations—Business Segments Other Than Local Gas Distribution—Interstate Gas Storage,” in the 2005 Form 10-K). The segment also began providing intrastate services in February 2006.
Our third-partyThird-party optimization activitiesservices are underprovided pursuant to a contract with an unaffiliated energy marketing company, which optimizesassists in the optimization of the value of our assets by engaging in marketing activities primarily through the use of commodity transactions and releases of temporarily unused portions of our upstream pipeline transportation capacity and gas storage capacity.transactions. In Oregon, we retain 80 percent of the pre-tax income from interstate storage services and optimization of storage and pipeline transportation capacityactivities when the costs of suchthe capacity used have not been included in utility rates, andor 33 percent of the pre-tax income from such optimization when the capacity costs have been included in utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a
deferred regulatory account for distributioncrediting to our core utility customers. We have a similar sharing mechanism in Washington for pre-tax income derived from interstate storage services and third-party optimization.optimization assistance.
Other
The Other business segment primarily consists of Northwest Natural’sa wholly-owned subsidiary, Financial Corporation (see Part II, Item 8., Note 2, “Consolidated Subsidiary Operations and Segment Information,” in the 2005 Form 10-K). Financial Corporation’s operating results for the three months ended June 30, 2006 were negligible lossesnet income of $0.1 million compared to $0.2 million in the second quarter of 2005. For the first quarterssix months of both 2006 and 2005.2005, results were net earnings of $0.1 million. In addition, the Other segment includes various other investments, including an investment in a leveraged aircraft lease.
Our net investment balances in Financial Corporation at March 31,June 30, 2006 and 2005 were $3.6$3.5 and $2.8$3.1 million, respectively. The $0.8$0.4 million increase was primarily due toreflects higher temporary cash investments, partially offset by a decline in the carrying value of long-term investments.
Operating Expenses
Operations and Maintenance
Operations and maintenance expenses in the firstsecond quarter of 2006 were $28.2$27.9 million, representing a $0.9 million, or 3 percent, increase over the second quarter of 2005. In addition to the costs of serving a 3.3 percent larger customer base, the following contributed to the increase in operations and maintenance expense:
Operations and maintenance expenses in the first six months of 2006 were an increase of $2.0 million, 4 percent higher than in the first quartersix months of 2005. The following summarizes the major factors that contributed to the $1.1 million increase in operations and maintenance expense:
General Taxes
General taxes, which are principally comprised of property taxes, payroll taxes and regulatory fees, increased $0.8$0.9 million, or 1216 percent, and $1.7 million, or 14 percent, in the first quarter ofthree- and six- month periods ended June 30, 2006, respectively, over the same periodperiods in 2005. Property taxes increased $0.3 million, or 8 percent, and $0.6 million, or 8 percent, in the three- and six- month periods
ended June 30, 2006, respectively, over the same periods in 2005, due to utility plant additions in 2006 and 2005. Regulatory fees increased $0.5 million or 28 percent, due toand $0.9 million in the three- and six-month periods ended June 30, 2006, respectively, over the same periods in 2005, reflecting increased gross operating revenues overand the prior year.timing impact of payments made in the second quarter of 2006.
Depreciation and Amortization
Depreciation and amortization expense increased by $0.6 million, or 4 percent, and $1.3 million, or 4 percent, in the three-month periodthree- and six-month periods ended March 31,June 30, 2006, respectively, compared to the same periodperiods in 2005. The increased expense is primarily due to additional investmentsreflects ongoing capital expenditures in utility propertyplant that were made primarily to meet continuing customer growth.growth and upgrade operating facilities.
Other Income and Expense – Net
The following table summarizes other income and expense-netexpense—net by primary components for the three months ended March 31:components:
Three months ended June 30, | Six months ended June 30, | |||||||||||||||||||||||
Thousands | 2006 | 2005 | 2006 | 2005 | 2006 | 2005 | ||||||||||||||||||
Gains from company-owned life insurance | $ | 1,383 | $ | 468 | ||||||||||||||||||||
Other income (expense): | ||||||||||||||||||||||||
Gains from Company-owned life insurance | $ | 414 | $ | 505 | $ | 1,797 | $ | 973 | ||||||||||||||||
Interest income | 84 | 46 | 191 | 183 | 275 | 229 | ||||||||||||||||||
Other non-operating expense | (603 | ) | (313 | ) | (215 | ) | (497 | ) | (818 | ) | (810 | ) | ||||||||||||
Interest income (charges) on deferred regulatory accounts | (296 | ) | 1 | |||||||||||||||||||||
Interest charges on deferred regulatory account balances | (89 | ) | 23 | (385 | ) | 24 | ||||||||||||||||||
Earnings from equity investments of Financial Corporation | (50 | ) | (137 | ) | 109 | 191 | 59 | 54 | ||||||||||||||||
Total other income and expense – net | $ | 518 | $ | 65 | ||||||||||||||||||||
Total other income | $ | 410 | $ | 405 | $ | 928 | $ | 470 | ||||||||||||||||
Other income and expense – net was unchanged in the second quarter of 2006 compared to 2005, and $0.5 million higher in the first quarter ofsix months ended June 30, 2006 compared to the first quarter ofsix months ended June 30, 2005. The increase in the six-month period was due to realized gains in the first quarter from company-owned life insurance, partially offset by higher non-operating expense and higher interest charges on deferred regulatory accounts.
Interest Charges – Net of Amounts Capitalized
Interest charges-netcharges—net of amounts capitalized increased $0.3 million, or 3 percent, and $1.0 million, or 6 percent, in the first quarter ofthree- and six-month periods ended June 30, 2006 was $0.7 million, or 1 percent, higher than in the three months ended March 31, 2005. The increase in 2006 wasand 2005, respectively, due to higher balances of total debt outstanding and higher interest rates during the period.outstanding.
Income Taxes
The effective corporate income tax rate from operations was 36.436.3 percent for each of the three-monthsix-month periods ended March 31,June 30, 2006 and 2005.
Financial Condition
Capital Structure
Our goal is to maintain a target capital structure comprised of 45 to 50 percent common stock equity and 50 to 55 percent long-term and short-term debt. When additional capital is required, debt or equity securities are issued depending upon both the target capital structure and market conditions. These sources also are used to meet long-term debt redemption requirements and short-term commercial
paper maturities (see “Liquidity and Capital Resources,” below). Our consolidated capital structure at March 31,June 30, 2006 and 2005 and at Dec. 31, 2005, including short-term debt, was as follows:
March 31, | Dec. 31, 2005 | June 30, | Dec. 31, 2005 | |||||||||||||||
2006 | 2005 | 2006 | 2005 | |||||||||||||||
Common stock equity | 51.6 | % | 54.0 | % | 47.2 | % | 51.4 | % | 51.9 | % | 47.2 | % | ||||||
Long-term debt | 41.8 | % | 43.7 | % | 42.0 | % | 41.4 | % | 45.7 | % | 42.0 | % | ||||||
Short-term debt, including current maturities of long-term debt | 6.6 | % | 2.3 | % | 10.8 | % | 7.2 | % | 2.4 | % | 10.8 | % | ||||||
Total | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | ||||||
The increase in common stock equity percentage in June of 2006 compared to December of 2005 is primarily related to a reduction of short-term debt of $70.9 million, combined with an increase in common stock equity at June 30, 2006 of $24.0 million. Achieving the target capital structure and maintaining sufficient liquidity are necessary to maintain attractive credit ratings and have access to capital markets at reasonable costs.
On May 25, 2000, we announcedThe Board has approved a program tofor the repurchase of up to 22.6 million shares, or up to $35$85 million in value, of NW Natural’sour common stock through a repurchasestock. Purchases under this program that has been extended annually. The purchases are made in the open market or through privately negotiated transactions. Since the program’s inception in 2000, we have repurchased 777,300812,700 shares of common stock at a total cost of $23.5 million. In April 2006, NW Natural’s Board$24.7 million, including 47,100 shares at a total cost of Directors extended$1.6 million in the share repurchase program through May 31, 2007 and increased the authorization from 2 million shares to 2.6 million shares and increased the dollar limit from $35 million to $85 millionfirst six months of 2006. (see “Financing Activities,” below).
Liquidity and Capital Resources
At March 31,June 30, 2006, we had $7.5$6.6 million of cash and cash equivalents compared to $2.7$40.3 million at MarchJune 30, 2005. The higher balance at June 30, 2005 reflects the temporary investment of a portion of the proceeds from a sale of $50 million of medium-term-notes in the second quarter of 2005. At Dec. 31, 2005, the balance in cash and cash equivalents was $7.1 million, which was comparable to the balance at Dec. 31, 2005.June 30, 2006. Short-term liquidity is provided by cash from operations and from the sale of commercial paper notes, which are supported by committed bank lines of credit totaling $200 million and available through Sept. 30, 2010 (see “Lines of Credit,” below, and Part II, Item 8., Note 6, in the 2005 Form 10-K). Short-termProceeds from the issuance of long-term debt balances are typically higher at the end of December each year due to seasonal working capital requirements, which reflect the financing of accounts receivable and natural gas inventories during the winter heating season. Short-term debt balances are significantly lower at the end of March as receivables and inventories are converted into cash, which is used to reducefinance capital expenditures, refinance maturing short-term debt.or long-term debt, and manage the capital structure.
Neither our Mortgage and Deed of Trust nor the indentures under which other long-term debt is issued contain credit rating triggers or stock price provisions that require the acceleration of debt repayment. Also, there are no rating triggers or stock price provisions contained in contracts or other agreements with third parties, except for agreements with certain counterparties under our Derivatives Policy, which require the affected party to provide substitute collateral such as cash, guaranty or letter of credit if credit ratings are lowered to non-investment grade, or in some cases if the mark-to-market value exceeds a certain threshold.
Based on the availability of short-term credit facilities and the ability to issue long-term debt and equity securities, we believe we have sufficient liquidity to satisfy our anticipated cash requirements, including the contractual obligations and investing and financing activities discussed below.
Off-Balance Sheet Arrangements
Except for certain lease and purchase commitments (see “Contractual Obligations,” below), we have no material off-balance sheet financing arrangements.
Contractual Obligations
Since Dec. 31, 2005, we entered into a new contract in the amount of $12.4 million for the purchase and installation of automated meter reading equipment. Other thanBesides this contract and other contracts entered into in the ordinary course of business, there were no material changes to our estimated future contractual obligations during the threesix months ended March 31,June 30, 2006. Our contractual obligations at Dec. 31, 2005 are described in Part II, Item 7., “Financial Condition—Liquidity and Capital Resources—Contractual Obligations,” in the 2005 Form 10-K.
Commercial Paper
Our primary source of short-term funds is from the sale of commercial paper notes payable. In addition to issuing commercial paper to meet seasonal working capital requirements, including the financing of gas purchases and accounts receivable, short-term debt is used to temporarily fund capital requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. Our outstanding commercial paper, which is sold through two commercial banks under an issuing and paying agency agreement, is supported by our committed bank lines of credit (see “Lines of Credit,” below, and Part II, Item 8., Note 6, in the 2005 Form 10-K). We had $50.4$55.8 million in commercial paper notes outstanding at March 31,June 30, 2006, compared to $10.5 millionno commercial paper outstanding at March 31,June 30, 2005 and $126.7 million outstanding at Dec. 31, 2005. Commercial paper balances are typically lower at the end of the first quarterand second quarters compared to year-end resulting from decreases in customer receivables and gas inventories due to collections from higher sales and the withdrawal of gas inventories from storage during the winter heating season.seasonality.
Lines of Credit
We have an agreementagreements for unsecured lines of credit totaling $200 million with five commercial banks. The bank lines of credit (bank lines) are available and committed for a term of five years, from Oct. 1, 2005 to Sept. 30, 2010.
Under the terms of these bank lines, we pay upfront fees and annual commitment fees but are not required to maintain compensating bank balances. The interest rates on outstanding loans, if any, under these bank lines are based on then-current market interest rates. All principal and unpaid interest under the bank lines is due and payable on Sept. 30, 2010. There were no outstanding balances on these lines of credit at March 31,June 30, 2006 or 2005, or at Dec. 31, 2005.
The lines of credit require us to maintain an indebtedness to total capitalization ratio of 65 percent or less. Failure to comply with this covenant would entitle the banks to terminate their lending commitments and to accelerate the maturity of any amounts outstanding. The Company was in compliance with this covenant at June 30, 2006 and at Dec. 31, 2005, and with the equivalent covenant in the prior year’s lines of credit at June 30, 2005.
Credit Ratings
The table below summarizes our credit ratings from three rating agencies, Standard and Poor’s Rating Services (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings (Fitch).
S&P | Moody’s | Fitch | ||||
Commercial paper (short-term debt) | A-1+ | P-1 | F1 | |||
Senior secured (long-term debt) | AA- | A2 | A+ | |||
Senior unsecured (long-term debt) | A+ | A3 | A | |||
Ratings outlook | Stable | Stable | Stable |
Each of the rating agencies has assigned usNW Natural an investment grade rating. These credit ratings are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell or hold ourNW Natural securities. Each rating should be evaluated independently of any other rating.
Cash Flows
Operating Activities
Year-over-year changes in our operating cash flows are primarily affected by net income, gas prices, deferred income taxes and other changes in working capital requirements, regulatory deferrals and other cash and non-cash adjustments to operating results. The overall change in cash flow from operating activities for the threesix months ended March 31,June 30, 2006 compared to the same period in 2005 was a decrease of $16.8$13.0 million, primarily due to a net decrease in cash from working capital changes of $21.9$20.9 million. The significant factors contributing to the cash flow changes in the first quarterhalf of 2006 compared to first quarterhalf of 2005 are as follows:
We have lease and purchase commitments relating to our operating activities that are financed with cash flows from operations (see “Liquidity and Capital Resources,” above, and Part II, Item 8., Note 12, in the 2005 Form 10-K).
Investing Activities
Cash requirements for investing activities in the first three monthshalf of 2006 totaled $12.7$33.9 million, down from $16.4$38.6 million in the same period of 2005. Cash requirements for the acquisition and construction of utility plant totaled $15.0$39.0 million, down from $20.0$41.4 million in the first quarterhalf of 2005.2005 due in part to a reductions in public works projects and purchases of general equipment.
Investments in non-utility property during the first three monthshalf of 2006 totaled $0.1$0.2 million, down from $0.2$0.9 million during the first three monthshalf of 2005.2005 due primarily to including amounts related to the start of improvements to the Company’s interstate gas storage facilities in 2005, which were not repeated in 2006.
In January 2005, Financial Corporation received proceeds from the sale of its limited partnership interests in three solar electric generation projects totaling $3.0 million.
Financing Activities
Cash used in financing activities in the first three monthshalf of 2006 totaled $85.4$98.0 million, downup from $101.3$70.6 million in the same period of 2005. The primary factor contributing to the $15.9$27.4 million decrease was the repaymentincrease
results from differences in short-term and long-term debt financings, which consisted of $76.3$78.9 million of short-term and long-term debt redemption in 2006, compared to $102.5 million of short-term debt in the first quarterredeemed, partially offset by $50 million of 2006 compared to $92.0 million in the same periodlong-term debt proceeds in 2005.
In 2000, we commenced a program to repurchase shares ofUnder our common stock through a repurchase program that has been extended through May 2007 (see “Capital Structure,” above). Wewe purchased 15,600 shares in the first quarter of 2006 at a cost of $0.5 million, compared to 80,50047,100 shares at a cost of $2.9$1.6 million in the first quarterhalf of 2006, compared to 134,800 shares at a cost of $4.9 million in the first half of 2005.
Ratios of Earnings to Fixed Charges
For the threesix months and 12 months ended March 31,June 30, 2006 and the 12 months ended Dec. 31, 2005, our ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were 7.23, 3.334.47, 3.37 and 3.32, respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed charges consist of interest on all indebtedness, the amortization of debt expense and discount or premium and the estimated interest portion of rentals charged to income. Because a significant part of our business is of a seasonal nature, the ratio for the interim period is not necessarily indicative of the results for a full year.
Contingencies
Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable in accordance with SFAS No. 5, “Accounting for Contingencies.” We update our estimates of loss contingencies and related disclosures when new information becomes available. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties, and we record accruals for loss contingencies based on an analysis of potential results, developed in consultation with outside counsel and consultants when appropriate. When information is sufficient to estimate only a range of potential liabilities, and no point within the range is more likely than any other, we recognize an accrued liability at the lower end of the range and disclose the range (see Note 7)9). It is possible, however, that the range of potential liabilities could be significantly different than amounts currently accrued and disclosed, and our financial condition and results of operations could be materially affected by changes in assumptions or estimates related to thesetheses contingencies.
We develop estimates of environmental liabilities and related costs based on currently available information, existing technology and environmental regulations. These costs include investigation, monitoring, and remediation. We received regulatory approval to defer and seek recovery of costs related to certain sites and believe the recovery of these costs is probable through the regulatory
process (see “Results of Operations—Regulatory Developments—Rate Mechanisms,” above). In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” we have recorded a regulatory asset for the amount expected to be recovered. We intend to pursue recovery of these environmental costs from our general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. At March 31,June 30, 2006, a cumulative $19.1$21.7 million in environmental costs has been recorded as a regulatory asset, including $14.4$16.0 million of costs paid to-date and $4.7$5.7 million of accrued estimated future environmental costs.expenditures. If it is determined that both the insurance recovery and future customer rate recovery of such costs is not probable, then the costs will be charged to expense in the period such determination is made. See Note 7.
Industrial Customers Switching from Transportation to Sales Service
In the fourth quarter of 2005, we settled a dispute with some large industrial customers related to gas costs charged to such customers upon electing to receive gas commodity under sales service instead of arranging for their own supplies through independent third parties. Two formal complaints filed with the OPUC in connection with this matter have been dismissed by the OPUC. The OPUC has also closed the investigation it opened to determine whether we had provided adequate information about rates to the industrial customers. We continue to contest claims of Georgia-Pacific Corporation in a related lawsuit more fully described in Note 7.9.
Forward-Looking Statements
This report and other presentations made by us from time to time may contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and other statements that are other than statements of historical facts. Our expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable
basis. However, each forward-looking statement involves uncertainties and is qualified in its entirety by reference to the following important factors, among others, that could cause our actual results to differ materially from those projected, including:
All subsequent forward-looking statements, whether written or oral and whether made by or on behalf of NW Natural, also are expressly qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for us to predict all such factors, nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
Item 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
We are exposed to various forms of market risk including commodity supply risk, weather risk, and interest rate risk. The following describes our exposure toFor further information regarding these risks.risks see Item 7A. in the 2005 Form 10-K and below. Also see Note 6, above, and Part II, Item 1A., “Risk Factors,” below.
Commodity Supply Risk
We enter into short-term, medium-term and long-term natural gas supply contracts, along with associated short-, medium- and long-term transportation capacity contracts. Historically, we have taken physical delivery of at least the minimum quantities specified in our natural gas supply contracts. These contracts are primarily index-based and subject to annual re-pricing, a process that is intended to reflect anticipated market price trends during the next year. Our PGA mechanisms in Oregon and Washington provide for the recovery from customers of actual commodity costs, except that, for Oregon customers, we absorb 33 percent of the higher cost of gas sold, or retain 33 percent of the lower cost, in either case as compared to the annual PGA price built into customer rates.
Market risks relatedBased on current forward curve prices, we began moderating our hedging positions compared to potential adverse changesprior years, but at the same time we have increased our gas inventory injections into storage while spot prices were lower. Typically, we have a higher percentage of the next gas year’s estimated purchase requirements hedged at this time of year. We may or may not increase our hedging positions to be closer to the level of the past few years, depending on movement in commodityforward market prices foreign exchange rates or counterparty credit qualityand our assessment of risk. Having a greater percentage of unhedged gas purchases may subject NW Natural to greater purchased gas cost variability in relationthe future as compared to these financial and physical contracts are discussed inprevious years. See Part II, Item 7A.1A., “Risk Factors,” below. Variations in the 2005 Form 10-K and below. Also see Note 4,gas costs are subject to our PGA mechanism. See Part I, Item 2.,”Results of Operations—Rate Mechanisms,” above.
Credit Risk
Credit exposure to financial derivative counterparties. Based on estimated fair value, our credit exposure to financial derivative counterparties relating to commodity swap contracts was $26.4$1.9 million at March 31,June 30, 2006. Our Derivatives Policy requires counterparties to have a minimum investment-grade credit rating at the time the derivative instrument is entered into, and the policy specifies limits on the contract amount and duration based on each counterparty’s credit rating. There were no credit rating downgrades for any of our counterparties during the quarter.
The following table summarizes our credit exposure, based on estimated fair value, and the corresponding counterparty credit ratings. The table uses credit ratings from S&P and Moody’s, reflecting the higher of the S&P or Moody’s rating, or a middle rating if the entity is split ratedsplit-rated with more than one rating level difference:difference:
Financial Derivative Exposure by Credit Rating Unrealized Fair Value Gain | Financial Derivative Exposure by Credit Rating Unrealized Fair Value Gain | |||||||||||||||||
March 31, | Dec. 31, 2005 | June 30, | Dec. 31, | |||||||||||||||
Thousands | 2006 | 2005 | 2006 | 2005 | 2005 | |||||||||||||
AAA/Aaa | $ | 940 | $ | — | $ | — | ||||||||||||
AA/Aa | 25,465 | 86,376 | 172,315 | $ | 1,853 | $ | 61,360 | $ | 172,315 | |||||||||
BBB/Baa | — | 1,619 | 3,346 | — | 1,104 | 3,346 | ||||||||||||
Total | $ | 26,405 | $ | 87,995 | $ | 175,661 | $ | 1,853 | $ | 62,464 | $ | 175,661 | ||||||
Credit exposure to customers.Increases in the market price of natural gas are expected to increase our credit exposure to customers. Also, higher gas prices have resulted in some of our largest industrial customers switching from transportation service to sales service. Under transportation service, the customer is purchasing its commodity supplies from an independent third party, while we only provide the transportation service for delivery of that gas to the customer’s premise. Under sales service, the customer is purchasing both its gas commodity supply and transportation service from us. With higher natural gas commodity prices, our credit exposure to large industrial sales customers has increased significantly.increased. We monitor and manage the credit exposure of our industrial sales customers through credit policies and
procedures, which are designed to reduce credit risk. These policies and procedures include an ongoing review of credit risks, including changes in the services provided to industrial customers as well as changes in market conditions and customers’ credit quality. Changes in credit risk may require us to obtain additional assurance, such as deposits, letters of credit, guarantees andor prepayments to reduce our credit exposure.
We also monitor and manage the credit exposure of our residential and commercial customers. This credit risk is largely mitigated by the nature of our regulated business and reasonably short collection terms, as well as by the consistent application of credit policies and procedures.
Item 4. | CONTROLS AND PROCEDURES |
(a) | Evaluation of Disclosure Controls and Procedures |
As of March 31,June 30, 2006, the principal executive officer and principal financial officer of the CompanyNW Natural have evaluated the effectiveness of the design and operation of the Company’sNW Natural’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (Exchange Act)). Based upon that evaluation, the principal executive officer and principal financial officer of the CompanyNW Natural have concluded that such disclosure controls and procedures are effective in timely alerting them to any materialensure that information relating to the Company and its consolidated subsidiaries required to be disclosed by NW Natural and included in the Company’sNW Natural’s reports filed with or furnished to the Securities and Exchange Commission under the Exchange Act.Act is accumulated and communicated to NW Natural’s management as appropriate to allow timely decisions regarding required disclosure.
(b) | Changes in Internal Control Over Financial Reporting |
There has been no change in the Company’sNW Natural’s internal control over financial reporting that occurred during the Company’sNW Natural’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’sNW Natural’s internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. | LEGAL PROCEEDINGS |
Litigation
For a discussion of certain pending legal proceedings, see Note 7,9, above.
Item 1A. | RISK FACTORS |
There are no material changesIn addition to the other information set forth in riskthis report, you should carefully consider the factors discussed in the first quarter of 2006. For a discussion of risk factors, see Part I, Item“Item 1A., “Risk Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2005, which could materially affect our business, financial condition or results of operations. The risks described in our Annual Report on Form 10-K.
Item 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
The following table provides information about purchases by us during the quarter ended March 31,June 30, 2006 of equity securities that are registered pursuant to Section 12 of the Exchange Act:
ISSUER PURCHASES OF EQUITY SECURITIES
Period | (a) Total Number of Shares Purchased(1) | (b) Average Price Paid per Share | (c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2) | (d) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs | (a) Total Number of Shares Purchased(1) | (b) Average Price Paid per Share | (c) Total Number of Shares | (d) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(2) | ||||||||||||||
Balance forward | 765,600 | $ | 11,870,463 | 777,300 | $ | 61,472,462 | ||||||||||||||||
01/01/06- 01/31/06 | 1,630 | $ | 35.95 | — | — | |||||||||||||||||
02/01/06- 02/28/06 | 26,040 | $ | 34.48 | — | — | |||||||||||||||||
03/01/06- 03/31/06 | 2,789 | $ | 33.94 | 11,700 | (398,001 | ) | ||||||||||||||||
04/01/06- 04/30/06 | 1,434 | $ | 34.35 | 3,900 | (137,301 | ) | ||||||||||||||||
05/01/06- 05/31/06 | 26,234 | $ | 34.35 | 31,500 | (1,074,464 | ) | ||||||||||||||||
06/01/06- 06/30/06 | 5,120 | $ | 35.13 | — | — | |||||||||||||||||
Total | 30,459 | $ | 34.51 | 777,300 | $ | 11,472,462 | 32,788 | $ | 34.47 | 812,700 | $ | 60,260,697 | ||||||||||
(1) | During the quarter ended |
(2) | On May 25, 2000, we announced a program to repurchase up to 2 million shares, or up to $35 million in value, of NW Natural’s common stock through a repurchase program that has been extended annually. The purchases are made in the open market or through privately negotiated transactions. Since the program’s inception, we have repurchased |
shares of common stock at a total cost of |
Item 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
NW Natural’s Annual Meeting of Shareholders was held in Portland, Oregon on May 25, 2006. At the meeting, four director-nominees were elected, as follows:
Director | Class | Term Expiring | Votes For | Votes Withheld | ||||||||||||||||||||||
Timothy P. Boyle | I | 2009 | 23,353,372 | 345,871 | ||||||||||||||||||||||
Mark S. Dodson | I | 2009 | 23,249,758 | 449,485 | ||||||||||||||||||||||
Randall C. Papé | I | 2009 | 17,658,362 | 6,040,881 | ||||||||||||||||||||||
Richard L. Woolworth | I | 2009 | 23,354,765 | 344,478 |
The other seven directors whose terms of office as directors continued after the Annual Meeting are: Martha L. (“Stormy”) Byorum, John D. Carter, C. Scott Gibson, Tod R. Hamachek, Richard G. Reiten, Kenneth Thrasher and Russell F. Tromley.
The following matters also were acted upon at the meeting:
The Company’s Long-Term Incentive Plan was reapproved by the following vote:
FOR | AGAINST | ABSTAIN | ||
22,472,902 | 859,712 | 366,626 |
Amendments to the Company’s Employee Stock Purchase Plan were approved by the following vote:
FOR | AGAINST | ABSTAIN | BROKER NON-VOTES | |||
16,846,839 | 709,245 | 356,490 | 5,786,668 |
The restatement of the Company’s Restated Articles of Incorporation was approved by the following vote:
FOR | AGAINST | ABSTAIN | ||
22,976,698 | 295,753 | 426,790 |
The amendment of Article IV of the Company’s Restated Articles of Incorporation was approved by the following vote:
FOR | AGAINST | ABSTAIN | ||
22,993,767 | 296,213 | 409,260 |
The ratification of the Audit Committee’s appointment of PricewaterhouseCoopers LLP as the Company’s independent public accountants for the year 2006 was approved by the following vote:
FOR | AGAINST | ABSTAIN | ||
23,225,158 | 282,091 | 191,992 |
There were no broker non-votes except on the proposal to amend the Employee Stock Purchase Plan, as shown above.
No other matters were acted upon at the meeting.
Item 5. | OTHER INFORMATION |
In addition to the arrangements described in our Proxy Statement relating to the 2006 Annual Meeting of Shareholders, since the commencement of his employment in 2004, David H. Anderson, Senior Vice President and Chief Financial Officer, has been entitled to a severance benefit equal to one-times annual salary if his employment is terminated by NW Natural without cause prior to Sept. 30, 2007.
Item 6. | EXHIBITS |
See Exhibit Index attached hereto.
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
NORTHWEST NATURAL GAS COMPANY | ||||
(Registrant) | ||||
Dated: | /s/ Stephen P. Feltz | |||
Stephen P. Feltz | ||||
Principal Accounting Officer | ||||
Treasurer and Controller |
NORTHWEST NATURAL GAS COMPANY
EXHIBIT INDEX
To
Quarterly Report on Form 10-Q
For Quarter Ended
March 31,June 30, 2006
Document | Exhibit Number | |
Statement re: Computation of Per Share Earnings | 11 | |
Computation of Ratio of Earnings to Fixed Charges | 12 | |
Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002 | 31.1 | |
Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002 | 31.2 | |
Certification of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | 32.1 |
41